165
| |
(5) | Jointly Owned Utility Facilities
|
Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the natureA reconciliation of the cost. Operating costsbeginning and expenses on the Consolidated Statementsending balances of Operations include the Company's share ofnet unrecognized tax benefits is as follows for the expenses of these facilities.years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 153 | | | $ | 145 | |
Additions based on tax positions related to the current year | 24 | | | 19 | |
Additions for tax positions of prior years | 13 | | | 6 | |
Reductions based on tax positions related to the current year | (19) | | | (14) | |
Reductions for tax positions of prior years | (83) | | | (1) | |
Statute of limitations | — | | | (4) | |
Settlements | (1) | | | 1 | |
Interest and penalties | 10 | | | 1 | |
Ending balance | $ | 97 | | | $ | 153 | |
The amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net asAs of December 31, 2018 (dollars2021 and 2020, the Company had unrecognized tax benefits totaling $100 million and $141 million, respectively, that if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.
(13)Employee Benefit Plans
Defined Benefit Plans
Domestic Operations
PacifiCorp, MidAmerican Energy and NV Energy sponsor defined benefit pension plans that cover a majority of all employees of BHE and its domestic energy subsidiaries. These pension plans include noncontributory defined benefit pension plans, supplemental executive retirement plans ("SERP") and restoration plans. PacifiCorp, MidAmerican Energy and NV Energy also provide certain postretirement healthcare and life insurance benefits through various plans to eligible retirees.
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Questar, exclusive of the Questar Pipeline Group (the "GT&S Transaction"). Defined benefit pension and postretirement benefits provided to the employees of BHE GT&S, which were part of the GT&S Transaction completed on November 1, 2020, are administered in millions):the respective plans sponsored by MidAmerican Energy. Initial pension and postretirement plan liabilities of $81 million and $37 million, respectively, resulted from the GT&S Transaction.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is generally calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
|
| | | | | | | | | | | | | | |
| | | | | Accumulated | | Construction |
| Company | | Facility In | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
PacifiCorp: | | | | | | | |
Jim Bridger Nos. 1-4 | 67 | % | | $ | 1,458 |
| | $ | 647 |
| | $ | 11 |
|
Hunter No. 1 | 94 |
| | 484 |
| | 182 |
| | — |
|
Hunter No. 2 | 60 |
| | 298 |
| | 121 |
| | 5 |
|
Wyodak | 80 |
| | 471 |
| | 229 |
| | — |
|
Colstrip Nos. 3 and 4 | 10 |
| | 248 |
| | 137 |
| | 6 |
|
Hermiston | 50 |
| | 180 |
| | 87 |
| | 1 |
|
Craig Nos. 1 and 2 | 19 |
| | 367 |
| | 241 |
| | — |
|
Hayden No. 1 | 25 |
| | 74 |
| | 37 |
| | — |
|
Hayden No. 2 | 13 |
| | 43 |
| | 22 |
| | — |
|
Foote Creek | 79 |
| | 40 |
| | 27 |
| | 1 |
|
Transmission and distribution facilities | Various | | 808 |
| | 246 |
| | 76 |
|
Total PacifiCorp | | | 4,471 |
| | 1,976 |
| | 100 |
|
MidAmerican Energy: | | | | | | | |
Louisa No. 1 | 88 | % | | 822 |
| | 443 |
| | 8 |
|
Quad Cities Nos. 1 and 2(1) | 25 |
| | 723 |
| | 407 |
| | 10 |
|
Walter Scott, Jr. No. 3 | 79 |
| | 641 |
| | 304 |
| | 2 |
|
Walter Scott, Jr. No. 4(2) | 60 |
| | 454 |
| | 167 |
| | 1 |
|
George Neal No. 4 | 41 |
| | 310 |
| | 164 |
| | 2 |
|
Ottumwa No. 1 | 52 |
| | 630 |
| | 209 |
| | 6 |
|
George Neal No. 3 | 72 |
| | 442 |
| | 196 |
| | 3 |
|
Transmission facilities | Various | | 257 |
| | 92 |
| | — |
|
Total MidAmerican Energy | | | 4,279 |
| | 1,982 |
| | 32 |
|
NV Energy: | | | | | | | |
Navajo | 11 | % | | 223 |
| | 176 |
| | — |
|
Valmy | 50 |
| | 389 |
| | 252 |
| | 1 |
|
Transmission facilities | Various | | 226 |
| | 49 |
| | 1 |
|
Total NV Energy | | | 838 |
| | 477 |
| | 2 |
|
BHE Pipeline Group - common facilities | Various | | 286 |
| | 173 |
| | — |
|
Total | | | $ | 9,874 |
| | $ | 4,608 |
| | $ | 134 |
|
| |
(1) | Includes amounts related to nuclear fuel. |
| |
(2) | Facility in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa revenue sharing arrangements totaling $319 million and $88 million, respectively. |
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
(6)Regulatory Matters | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | 30 | | | $ | 17 | | | $ | 16 | | | $ | 12 | | | $ | 7 | | | $ | 8 | |
Interest cost | 78 | | | 93 | | | 111 | | | 19 | | | 21 | | | 27 | |
Expected return on plan assets | (134) | | | (140) | | | (154) | | | (22) | | | (34) | | | (40) | |
Settlement | 3 | | | — | | | — | | | — | | | — | | | — | |
Net amortization | 25 | | | 32 | | | 31 | | | (3) | | | (4) | | | (6) | |
Net periodic benefit cost (credit) | $ | 2 | | | $ | 2 | | | $ | 4 | | | $ | 6 | | | $ | (10) | | | $ | (11) | |
Regulatory AssetsFunded Status
RegulatoryThe following table is a reconciliation of the fair value of plan assets represent costs that are expected to be recovered in future regulated rates. for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 2,824 | | | $ | 2,656 | | | $ | 744 | | | $ | 742 | |
Employer contributions | 13 | | | 13 | | | 14 | | | 3 | |
Participant contributions | — | | | — | | | 9 | | | 8 | |
Actual return on plan assets | 234 | | | 373 | | | 53 | | | 40 | |
Settlement | (134) | | | — | | | — | | | — | |
Benefits paid | (142) | | | (218) | | | (51) | | | (49) | |
Plan assets at fair value, end of year | $ | 2,795 | | | $ | 2,824 | | | $ | 769 | | | $ | 744 | |
The Company's regulatory assets reflectedfollowing table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 3,077 | | | $ | 2,878 | | | $ | 758 | | | $ | 673 | |
Service cost | 30 | | | 17 | | | 12 | | | 7 | |
Interest cost | 78 | | | 93 | | | 19 | | | 21 | |
Participant contributions | — | | | — | | | 9 | | | 8 | |
Actuarial (gain) loss | (132) | | | 226 | | | (35) | | | 61 | |
Amendment | — | | | — | | | 2 | | | — | |
Settlement | (134) | | | — | | | — | | | — | |
Acquisition | — | | | 81 | | | — | | | 37 | |
Benefits paid | (142) | | | (218) | | | (51) | | | (49) | |
Benefit obligation, end of year | $ | 2,777 | | | $ | 3,077 | | | $ | 714 | | | $ | 758 | |
Accumulated benefit obligation, end of year | $ | 2,713 | | | $ | 2,999 | | | | | |
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets consist of the following as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 2,795 | | | $ | 2,824 | | | $ | 769 | | | $ | 744 | |
Benefit obligation, end of year | 2,777 | | | 3,077 | | | 714 | | | 758 | |
Funded status | $ | 18 | | | $ | (253) | | | $ | 55 | | | $ | (14) | |
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 204 | | | $ | 43 | | | $ | 60 | | | $ | 20 | |
Other current liabilities | (13) | | | (13) | | | — | | | — | |
Other long-term liabilities | (173) | | | (283) | | | (5) | | | (34) | |
Amounts recognized | $ | 18 | | | $ | (253) | | | $ | 55 | | | $ | (14) | |
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Employee benefit plans(1) | 16 years
| | $ | 773 |
| | $ | 675 |
|
Asset retirement obligations | 17 years
| | 375 |
| | 334 |
|
Asset disposition costs | Various | | 358 |
| | 387 |
|
Deferred income taxes(2) | Various | | 196 |
| | 143 |
|
Deferred operating costs | 10 years
| | 141 |
| | 147 |
|
Abandoned projects | 2 years
| | 134 |
| | 156 |
|
Unrealized loss on regulated derivative contracts | 2 years
| | 120 |
| | 122 |
|
Deferred net power costs | 2 years
| | 103 |
| | 58 |
|
Unamortized contract values | 5 years
| | 79 |
| | 89 |
|
Other | Various | | 788 |
| | 839 |
|
Total regulatory assets | | | $ | 3,067 |
| | $ | 2,950 |
|
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 171 |
| | $ | 189 |
|
Noncurrent assets | | | 2,896 |
| | 2,761 |
|
Total regulatory assets | | | $ | 3,067 |
| | $ | 2,950 |
|
| |
(1) | Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized. |
| |
(2) | Amounts primarily represent income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. |
The Company had regulatory assets not earning a return on investment of $1.3 billion and $1.1 billion as of December 31, 2018 and 2017, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 3,923 |
| | $ | 4,143 |
|
Cost of removal(2) | 28 years
| | 2,426 |
| | 2,349 |
|
Levelized depreciation | 30 years
| | 329 |
| | 332 |
|
Asset retirement obligations | 34 years
| | 163 |
| | 177 |
|
Impact fees | 4 years
| | 88 |
| | 89 |
|
Other | Various | | 577 |
| | 421 |
|
Total regulatory liabilities | | | $ | 7,506 |
| | $ | 7,511 |
|
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 160 |
| | $ | 202 |
|
Noncurrent liabilities | | | 7,346 |
| | 7,309 |
|
Total regulatory liabilities | | | $ | 7,506 |
| | $ | 7,511 |
|
| |
(1) | Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. See Note 11 for further discussion of 2017 Tax Reform impacts. |
| |
(2) | Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost. |
ALP General Tariff Application ("GTA")
In 2014, ALP filed a GTA requesting the Alberta Utilities Commission ("AUC") to approve revenue requirements of C$811 million for 2015 and C$1.0 billion for 2016, primarily due to continued investment in capital projects as directed by the Alberta Electric System Operator. ALP amended the GTA in June 2015 to propose transmission tariff relief measures for customers and modifications to its capital structure. ALP also amended and updated the GTA in October 2015, reducing the requested revenue requirements to C$672 million for 2015 and C$704 million for 2016. In May 2016, the AUC issued its decision pertaining to the 2015-2016 GTA. ALP filed its 2015-2016 GTA compliance filing in July 2016 to comply with the AUC's decision.
The compliance filing requestedSERPs and restoration plan have no plan assets; however, the AUC to approve revenue requirements of C$599 million for 2015 and C$685 million for 2016. The decreased revenue requirements requested in the compliance filing, as compared to the 2015-2016 GTA filing updated in October 2015, were primarily due to the AUC approval of ALP's proposed immediate tariff relief of C$415 million for customers for 2015 and 2016, through (i) the discontinuance of construction work-in-progress ("CWIP") in rate base and the return to allowance for funds used during construction ("AFUDC") accounting effective January 1, 2015, resulting in a C$82 million reduction of revenue requirement and the refund of C$277 million previously collected as CWIP in rate base as part of ALP's transmission tariffs during 2011-2014 less related returns of C$12 million and (ii) a change to the flow through method for calculating income taxes for 2016, resulting in further tariff relief of C$68 million.
Operating revenue for the year ended December 31, 2016, included a one-time reduction of $200 million from the 2015-2016 GTA decision received in May 2016 at ALP. The 2015-2016 GTA decision required ALP to refund $200 million to customers in 2016 through reduced monthly billings for the change from receiving cash during construction for the return on CWIP in rate base to recording allowance for borrowed and equity funds used during construction related to construction expenditures during the 2011 to 2014 time period. This amount is offset with higher capitalized interest and allowance for equity funds in the Consolidated Statements of Operations. In addition, the decision required ALP to change to the flow through method of recognizing income tax expense effective January 1, 2016. This change reduced operating revenue by $45 million for the year ended December 31, 2016, with offsetting impacts to income tax expense in the Consolidated Statements of Operations.
(7)Investments and Restricted Cash and Cash Equivalents and Investments
Investments and restricted cash and cash equivalents and investments consists of the following as of December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
Investments: | | | |
BYD Company Limited common stock | $ | 1,435 |
| | $ | 1,961 |
|
Rabbi trusts | 371 |
| | 441 |
|
Other | 168 |
| | 124 |
|
Total investments | 1,974 |
| | 2,526 |
|
| | | |
Equity method investments: | | | |
BHE Renewables tax equity investments | 1,661 |
| | 1,025 |
|
Electric Transmission Texas, LLC | 527 |
| | 524 |
|
Bridger Coal Company | 99 |
| | 137 |
|
Other | 153 |
| | 148 |
|
Total equity method investments | 2,440 |
| | 1,834 |
|
| | | |
Restricted cash and cash equivalents and investments: | | | |
Quad Cities Station nuclear decommissioning trust funds | 504 |
| | 515 |
|
Restricted cash and cash equivalents | 256 |
| | 348 |
|
Total restricted cash and cash equivalents and investments | 760 |
| | 863 |
|
| | | |
Total investments and restricted cash and cash equivalents and investments | $ | 5,174 |
| | $ | 5,223 |
|
| | | |
Reflected as: | | | |
Other current assets | $ | 271 |
| | $ | 351 |
|
Noncurrent assets | 4,903 |
| | 4,872 |
|
Total investments and restricted cash and cash equivalents and investments | $ | 5,174 |
| | $ | 5,223 |
|
Investments
BHE's investment in BYD Company Limited common stock is accounted for as a marketable security with changes in fair value recognized in net income.
has Rabbi trusts primarilythat hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were establishedother investments to hold investments used to fundprovide funding for the obligations of various nonqualified executive and director compensation plans and to pay the costsfuture cash requirements of the trusts.SERPs and restoration plan. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value.
The portionvalue, plus the fair market value of unrealized losses related to marketable securities still heldother Rabbi trust investments, was $343 million and $303 million as of December 31, 2018 is calculated2021 and 2020, respectively. These assets are not included in the plan assets in the above table, but are reflected in noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets.
The fair value of plan assets, projected benefit obligation and accumulated benefit obligation for (1) pension and other postretirement benefit plans with a projected benefit obligation in excess of the fair value of plan assets and (2) pension plans with an accumulated benefit obligation in excess of the fair value of plan assets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Fair value of plan assets | $ | — | | | $ | 1,782 | | | $ | 137 | | | $ | 417 | |
| | | | | | | |
Projected benefit obligation | $ | 186 | | | $ | 2,069 | | | $ | 142 | | | $ | 451 | |
| | | | | | | |
Fair value of plan assets | $ | — | | | $ | 1,064 | | | | | |
| | | | | | | |
Accumulated benefit obligation | $ | 185 | | | $ | 1,341 | | | | | |
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net loss (gain) | $ | 343 | | | $ | 612 | | | $ | (34) | | | $ | 34 | |
Prior service credit | (1) | | | (1) | | | (1) | | | (9) | |
Regulatory deferrals | 11 | | | 2 | | | 2 | | | 3 | |
Total | $ | 353 | | | $ | 613 | | | $ | (33) | | | $ | 28 | |
|
| | | |
| Year Ended |
| December 31, |
| 2018 |
Losses on marketable securities recognized during the period | $ | (538 | ) |
Less: Net gains recognized during the period on marketable securities sold during the period | 2 |
|
Unrealized losses recognized during the period on marketable securities still held at the reporting date | $ | (540 | ) |
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2021 and 2020 is as follows (in millions): | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | Regulatory | | Comprehensive | | |
| Asset | | Liability | | Loss | | Total |
Pension | | | | | | | |
Balance, December 31, 2019 | $ | 661 | | | $ | (33) | | | $ | 24 | | | $ | 652 | |
Net (gain) loss arising during the year | (30) | | | 13 | | | 10 | | | (7) | |
| | | | | | | |
| | | | | | | |
Net amortization | (31) | | | — | | | (1) | | | (32) | |
Total | (61) | | | 13 | | | 9 | | | (39) | |
Balance, December 31, 2020 | 600 | | | (20) | | | 33 | | | 613 | |
Net gain arising during the year | (177) | | | (44) | | | (10) | | | (231) | |
| | | | | | | |
Settlement | (9) | | | 5 | | | — | | | (4) | |
Net amortization | (24) | | | — | | | (1) | | | (25) | |
Total | (210) | | | (39) | | | (11) | | | (260) | |
Balance, December 31, 2021 | $ | 390 | | | $ | (59) | | | $ | 22 | | | $ | 353 | |
Equity Method Investments | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | Regulatory | | Comprehensive | | |
| Asset | | Liability | | Loss | | Total |
Other Postretirement | | | | | | | |
Balance, December 31, 2019 | $ | 4 | | | $ | (32) | | | $ | (3) | | | $ | (31) | |
Net loss arising during the year | 36 | | | 12 | | | 7 | | | 55 | |
| | | | | | | |
Net amortization | 7 | | | (3) | | | — | | | 4 | |
Total | 43 | | | 9 | | | 7 | | | 59 | |
Balance, December 31, 2020 | 47 | | | (23) | | | 4 | | | 28 | |
Net gain arising during the year | (40) | | | (22) | | | (3) | | | (65) | |
Net prior service cost arising during the year | 1 | | | — | | | — | | | 1 | |
Net amortization | 3 | | | — | | | — | | | 3 | |
Total | (36) | | | (22) | | | (3) | | | (61) | |
Balance, December 31, 2021 | $ | 11 | | | $ | (45) | | | $ | 1 | | | $ | (33) | |
Plan Assumptions
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 2.98 | % | | 2.60 | % | | 3.32 | % | | 2.95 | % | | 2.59 | % | | 3.24 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.22 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.44 | % | | 2.94 | % | | N/A | | N/A | | N/A |
2021 | 2.45 | % | | 2.25 | % | | 2.94 | % | | N/A | | N/A | | N/A |
2022 | 2.56 | % | | 2.25 | % | | 3.02 | % | | N/A | | N/A | | N/A |
2023 | 2.56 | % | | 2.65 | % | | 3.02 | % | | N/A | | N/A | | N/A |
2024 and beyond | 2.83 | % | | 2.65 | % | | 3.02 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | | |
Discount rate | 2.60 | % | | 3.32 | % | | 4.25 | % | | 2.59 | % | | 3.24 | % | | 4.21 | % |
Expected return on plan assets | 5.39 | % | | 5.94 | % | | 6.48 | % | | 3.35 | % | | 5.42 | % | | 6.39 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A | | N/A | | N/A |
Interest crediting rate for cash balance plan | 2.45 | % | | 2.44 | % | | 3.22 | % | | N/A | | N/A | | N/A |
In establishing its assumption as to the expected return on plan assets, the Company utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
| | | | | | | | | | | |
| 2021 | | 2020 |
Assumed healthcare cost trend rates as of December 31: | | | |
Healthcare cost trend rate assumed for next year | 6.00 | % | | 6.30 | % |
Rate that the cost trend rate gradually declines to | 5.00 | % | | 5.00 | % |
Year that the rate reaches the rate it is assumed to remain at | 2025 | | 2025 |
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $13 million and $5 million, respectively, during 2022. Funding to the established pension trusts is based upon the actuarially determined costs of the plans and the requirements of the IRC, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. The Company considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. The Company evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plans.
The expected benefit payments to participants in the Company's pension and other postretirement benefit plans for 2022 through 2026 and for the five years thereafter are summarized below (in millions):
| | | | | | | | | | | |
| Projected Benefit |
| Payments |
| | | Other |
| Pension | | Postretirement |
| | | |
2022 | $ | 210 | | | $ | 54 | |
2023 | 203 | | | 54 | |
2024 | 195 | | | 54 | |
2025 | 193 | | | 53 | |
2026 | 193 | | | 51 | |
2027-2031 | 837 | | | 229 | |
Plan Assets
Investment Policy and Asset Allocations
The Company's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
The target allocations (percentage of plan assets) for the Company's pension and other postretirement benefit plan assets are as follows as of December 31, 2021:
| | | | | | | | | | | |
| | | Other |
| Pension | | Postretirement |
| % | | % |
PacifiCorp: | | | |
Debt securities(1) | 55-85 | | 70-80 |
Equity securities(1) | 25-35 | | 20-30 |
Limited partnership interests | 0-10 | | 0-1 |
| | | |
| | | |
MidAmerican Energy: | | | |
Debt securities(1) | 60-80 | | 25-35 |
Equity securities(1) | 20-40 | | 65-75 |
| | | |
Other | 0-15 | | 0-5 |
| | | |
NV Energy: | | | |
Debt securities(1) | 85-100 | | 67-88 |
Equity securities(1) | 0-15 | | 12-33 |
(1)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for the Company's defined benefit pension plans (in millions):
| | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | | | |
| Level 1 | | Level 2 | | | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | — | | | $ | 64 | | | | | $ | 64 | |
Debt securities: | | | | | | | |
United States government obligations | 142 | | | — | | | | | 142 | |
| | | | | | | |
Corporate obligations | — | | | 912 | | | | | 912 | |
Municipal obligations | — | | | 66 | | | | | 66 | |
Agency, asset and mortgage-backed obligations | — | | | 93 | | | | | 93 | |
Equity securities: | | | | | | | |
United States companies | 135 | | | — | | | | | 135 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 277 | | | $ | 1,135 | | | | | 1,412 | |
Investment funds(2) measured at net asset value | | | | | | | 1,349 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 34 | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 2,795 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | — | | | $ | 79 | | | | | $ | 79 | |
Debt securities: | | | | | | | |
United States government obligations | 52 | | | — | | | | | 52 | |
| | | | | | | |
Corporate obligations | — | | | 748 | | | | | 748 | |
Municipal obligations | — | | | 69 | | | | | 69 | |
| | | | | | | |
Equity securities: | | | | | | | |
United States companies | 224 | | | — | | | | | 224 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 276 | | | $ | 896 | | | | | 1,172 | |
Investment funds(2) measured at net asset value | | | | | | | 1,521 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 88 | |
Real estate funds measured at net asset value | | | | | | | 43 | |
Total assets measured at fair value | | | | | | | $ | 2,824 | |
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 54% and 46%, respectively, for 2021 and 69% and 31%, respectively, for 2020. Additionally, these funds are invested in United States and international securities of approximately 89% and 11%, respectively, for 2021 and 79% and 21%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
The following table presents the fair value of plan assets, by major category, for the Company's defined benefit other postretirement plans (in millions):
| | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | | | |
| Level 1 | | Level 2 | | | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | 12 | | | $ | 4 | | | | | $ | 16 | |
Debt securities: | | | | | | | |
United States government obligations | 27 | | | — | | | | | 27 | |
| | | | | | | |
Corporate obligations | — | | | 85 | | | | | 85 | |
Municipal obligations | — | | | 43 | | | | | 43 | |
Agency, asset and mortgage-backed obligations | — | | | 38 | | | | | 38 | |
Equity securities: | | | | | | | |
United States companies | 4 | | | — | | | | | 4 | |
| | | | | | | |
Investment funds(2) | 394 | | | — | | | | | 394 | |
| | | | | | | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 437 | | | $ | 170 | | | | | 607 | |
Investment funds(2) measured at net asset value | | | | | | | 161 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 1 | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 769 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | 20 | | | $ | 2 | | | | | $ | 22 | |
Debt securities: | | | | | | | |
United States government obligations | 15 | | | — | | | | | 15 | |
| | | | | | | |
Corporate obligations | — | | | 102 | | | | | 102 | |
Municipal obligations | — | | | 82 | | | | | 82 | |
Agency, asset and mortgage-backed obligations | — | | | 47 | | | | | 47 | |
Equity securities: | | | | | | | |
United States companies | 6 | | | — | | | | | 6 | |
| | | | | | | |
Investment funds(2) | 299 | | | — | | | | | 299 | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 340 | | | $ | 233 | | | | | 573 | |
Investment funds(2) measured at net asset value | | | | | | | 167 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 4 | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 744 | |
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 55% and 45%, respectively, for 2021 and 40% and 60%, respectively, for 2020. Additionally, these funds are invested in United States and international securities of approximately 88% and 12%, respectively, for 2021 and 79% and 21%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Foreign Operations
Certain wholly-owned subsidiaries of Northern Powergrid participate in the Northern Powergrid group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the "UK Plan"), which provides pension and other related defined benefits, based on final pensionable pay, to the employees of Northern Powergrid. The UK Plan is closed to employees hired after July 23, 1997. Employees hired after that date are covered by a defined contribution plan sponsored by a wholly-owned subsidiary of Northern Powergrid.
Net Periodic Benefit Cost
For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by including the difference between expected and actual investment returns after the first year in which they occur.
Net periodic benefit cost for the UK Plan included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Service cost | $ | 16 | | | $ | 16 | | | $ | 16 | |
Interest cost | 31 | | | 40 | | | 49 | |
Expected return on plan assets | (111) | | | (101) | | | (100) | |
Settlement | 10 | | | 17 | | | 26 | |
Net amortization | 55 | | | 43 | | | 46 | |
Net periodic benefit cost | $ | 1 | | | $ | 15 | | | $ | 37 | |
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Plan assets at fair value, beginning of year | $ | 2,334 | | | $ | 2,151 | |
Employer contributions | 28 | | | 56 | |
Participant contributions | 1 | | | 1 | |
Actual return on plan assets | 148 | | | 181 | |
Settlement | (51) | | | (63) | |
Benefits paid | (72) | | | (67) | |
Foreign currency exchange rate changes | (25) | | | 75 | |
Plan assets at fair value, end of year | $ | 2,363 | | | $ | 2,334 | |
The following table is a reconciliation of the benefit obligation for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Benefit obligation, beginning of year | $ | 2,205 | | | $ | 2,019 | |
Service cost | 16 | | | 16 | |
Interest cost | 31 | | | 40 | |
Participant contributions | 1 | | | 1 | |
Actuarial (gain) loss | (105) | | | 188 | |
Settlement | (51) | | | (63) | |
| | | |
Benefits paid | (72) | | | (67) | |
Foreign currency exchange rate changes | (22) | | | 71 | |
Benefit obligation, end of year | $ | 2,003 | | | $ | 2,205 | |
Accumulated benefit obligation, end of year | $ | 1,778 | | | $ | 1,963 | |
The funded status of the UK Plan and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Plan assets at fair value, end of year | $ | 2,363 | | | $ | 2,334 | |
Benefit obligation, end of year | 2,003 | | | 2,205 | |
Funded status | $ | 360 | | | $ | 129 | |
| | | |
Amounts recognized on the Consolidated Balance Sheets: | | | |
Other assets | $ | 360 | | | $ | 129 | |
Unrecognized Amounts
The portion of the funded status of the UK Plan not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Net loss | $ | 400 | | | $ | 612 | |
Prior service cost | 5 | | | 6 | |
Total | $ | 405 | | | $ | 618 | |
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost, which are included in accumulated other comprehensive loss on the Consolidated Balance Sheets, for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Balance, beginning of year | $ | 618 | | | $ | 549 | |
Net loss arising during the year | (143) | | | 108 | |
| | | |
Settlement | (10) | | | (17) | |
Net amortization | (55) | | | (43) | |
Foreign currency exchange rate changes | (5) | | | 21 | |
Total | (213) | | | 69 | |
Balance, end of year | $ | 405 | | | $ | 618 | |
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Benefit obligations as of December 31: | | | | | |
Discount rate | 1.95 | % | | 1.40 | % | | 2.10 | % |
Rate of compensation increase | 3.45 | % | | 3.05 | % | | 3.30 | % |
Rate of future price inflation | 2.95 | % | | 2.55 | % | | 2.80 | % |
| | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | |
Discount rate | 1.40 | % | | 2.10 | % | | 2.90 | % |
Expected return on plan assets | 4.85 | % | | 5.00 | % | | 5.10 | % |
Rate of compensation increase | 3.05 | % | | 3.30 | % | | 3.55 | % |
Rate of future price inflation | 2.55 | % | | 2.80 | % | | 3.05 | % |
Contributions and Benefit Payments
Employer contributions to the UK Plan are expected to be £12 million during 2022. The expected benefit payments to participants in the UK Plan for 2022 through 2026 and for the five years thereafter, excluding lump sum settlement elections and using the foreign currency exchange rate as of December 31, 2021, are summarized below (in millions):
| | | | | |
2022 | $ | 73 | |
2023 | 75 | |
2024 | 77 | |
2025 | 79 | |
2026 | 81 | |
2027-2031 | 436 | |
Plan Assets
Investment Policy and Asset Allocations
The investment policy for the UK Plan is to balance risk and return through a diversified portfolio of debt securities, equity securities, real estate and other asset classes. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The UK Plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with Northern Powergrid. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments. The return on assets assumption is based on a weighted-average of the expected historical performance for the types of assets in which the UK Plan invests.
The target allocations (percentage of plan assets) for the UK Plan assets are as follows as of December 31, 2021:
| | | | | |
| % |
Debt securities(1) | 60-70 |
Equity securities(1) | 10-20 |
Real estate funds and other | 15-25 |
(1)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of the UK Plan assets, by major category (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | 5 | | | $ | 27 | | | $ | — | | | $ | 32 | |
Debt securities: | | | | | | | |
United Kingdom government obligations | 1,308 | | | — | | | — | | | 1,308 | |
| | | | | | | |
| | | | | | | |
Equity securities: | | | | | | | |
Investment funds(2) | — | | | 646 | | | — | | | 646 | |
Real estate funds | — | | | — | | | 269 | | | 269 | |
Total | $ | 1,313 | | | $ | 673 | | | $ | 269 | | | 2,255 | |
Investment funds(2) measured at net asset value | | | | | | | 108 | |
Total assets measured at fair value | | | | | | | $ | 2,363 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | 5 | | | $ | 49 | | | $ | — | | | $ | 54 | |
Debt securities: | | | | | | | |
| | | | | | | |
United Kingdom government obligations | 1,102 | | | — | | | — | | | 1,102 | |
| | | | | | | |
| | | | | | | |
Equity securities: | | | | | | | |
Investment funds(2) | — | | | 833 | | | — | | | 833 | |
Real estate funds | — | | | — | | | 237 | | | 237 | |
Total | $ | 1,107 | | | $ | 882 | | | $ | 237 | | | 2,226 | |
Investment funds(2) measured at net asset value | | | | | | | 108 | |
Total assets measured at fair value | | | | | | | $ | 2,334 | |
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 23% and 77%, respectively, for 2021 and 40% and 60%, respectively, for 2020.
The fair value of the UK Plan's assets are determined similar to the plan assets of the domestic plans as previously discussed.
The following table reconciles the beginning and ending balances of the UK Plan assets measured at fair valueusing significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Real Estate Funds |
| 2021 | | 2020 | | 2019 |
| | | | | |
Beginning balance | $ | 237 | | | $ | 243 | | | $ | 239 | |
Actual return on plan assets still held at period end | 35 | | | (13) | | | (5) | |
| | | | | |
Foreign currency exchange rate changes | (3) | | | 7 | | | 9 | |
Ending balance | $ | 269 | | | $ | 237 | | | $ | 243 | |
Defined Contribution Plans
The Company sponsors various defined contribution plans covering substantially all employees. The Company's contributions vary depending on the plan, but matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. The Company's contributions to these plans were $137 million, $127 million and $115 million for the years ended December 31, 2021, 2020 and 2019, respectively.
(14)Asset Retirement Obligations
The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $2.4 billion as of December 31, 2021 and 2020.
The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Fossil fuel facilities | $ | 466 | | | $ | 529 | |
Quad Cities Station | 427 | | | 376 | |
Wind generating facilities | 299 | | | 273 | |
Solar generating facilities | 25 | | | 24 | |
Offshore pipeline facilities | 14 | | | 16 | |
Other | 109 | | | 123 | |
Total asset retirement obligations | $ | 1,340 | | | $ | 1,341 | |
| | | |
Quad Cities Station nuclear decommissioning trust funds | $ | 768 | | | $ | 676 | |
The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 1,341 | | | $ | 1,272 | |
Change in estimated costs | 81 | | | 46 | |
Acquisitions | — | | | 122 | |
Additions | 15 | | | 51 | |
Retirements | (144) | | | (201) | |
Accretion | 47 | | | 51 | |
Ending balance | $ | 1,340 | | | $ | 1,341 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 130 | | | $ | 184 | |
Other long-term liabilities | 1,210 | | | 1,157 | |
Total ARO liability | $ | 1,340 | | | $ | 1,341 | |
The Nuclear Regulatory Commission regulates the decommissioning of nuclear generating facilities, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the Nuclear Regulatory Commission providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning.
Certain of the Company's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites, and as such, each subsidiary is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.
(15)Fair Value Measurements
The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has investedvarious financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in projects sponsoredactive markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by third parties, commonly referredobservable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.
The following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2021: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | 5 | | | $ | 271 | | | $ | 73 | | | $ | (47) | | | $ | 302 | |
Foreign currency exchange rate derivatives | — | | | 3 | | | — | | | — | | | 3 | |
Interest rate derivatives | 1 | | | 3 | | | 20 | | | — | | | 24 | |
Mortgage loans held for sale | — | | | 1,263 | | | — | | | — | | | 1,263 | |
Money market mutual funds | 554 | | | — | | | — | | | — | | | 554 | |
Debt securities: | | | | | | | | | |
United States government obligations | 232 | | | — | | | — | | | — | | | 232 | |
International government obligations | — | | | 2 | | | — | | | — | | | 2 | |
Corporate obligations | — | | | 90 | | | — | | | — | | | 90 | |
Municipal obligations | — | | | 3 | | | — | | | — | | | 3 | |
Agency, asset and mortgage-backed obligations | — | | | 2 | | | — | | | — | | | 2 | |
| | | | | | | | | |
Equity securities: | | | | | | | | | |
United States companies | 428 | | | — | | | — | | | — | | | 428 | |
International companies | 7,703 | | | — | | | — | | | — | | | 7,703 | |
Investment funds | 237 | | | — | | | — | | | — | | | 237 | |
| $ | 9,160 | | | $ | 1,637 | | | $ | 93 | | | $ | (47) | | | $ | 10,843 | |
Liabilities: | | | | | | | | | |
Commodity derivatives | $ | (2) | | | $ | (113) | | | $ | (224) | | | $ | 73 | | | $ | (266) | |
Foreign currency exchange rate derivatives | — | | | (3) | | | — | | | — | | | (3) | |
Interest rate derivatives | — | | | (7) | | | (1) | | | — | | | (8) | |
| $ | (2) | | | $ | (123) | | | $ | (225) | | | $ | 73 | | | $ | (277) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | 1 | | | $ | 73 | | | $ | 135 | | | $ | (21) | | | $ | 188 | |
Foreign currency exchange rate derivatives | — | | | 20 | | | — | | | — | | | 20 | |
Interest rate derivatives | — | | | — | | | 62 | | | — | | | 62 | |
Mortgage loans held for sale | — | | | 2,001 | | | — | | | — | | | 2,001 | |
Money market mutual funds | 873 | | | — | | | — | | | — | | | 873 | |
Debt securities: | | | | | | | | | |
United States government obligations | 200 | | | — | | | — | | | — | | | 200 | |
International government obligations | — | | | 5 | | | — | | | — | | | 5 | |
Corporate obligations | — | | | 73 | | | — | | | — | | | 73 | |
Municipal obligations | — | | | 2 | | | — | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | — | | | 6 | | | — | | | — | | | 6 | |
| | | | | | | | | |
Equity securities: | | | | | | | | | |
United States companies | 381 | | | — | | | — | | | — | | | 381 | |
International companies | 5,906 | | | — | | | — | | | — | | | 5,906 | |
Investment funds | 201 | | | — | | | — | | | — | | | 201 | |
| $ | 7,562 | | | $ | 2,180 | | | $ | 197 | | | $ | (21) | | | $ | 9,918 | |
Liabilities: | | | | | | | | | |
Commodity derivatives | $ | (1) | | | $ | (90) | | | $ | (19) | | | $ | 56 | | | $ | (54) | |
Foreign currency exchange rate derivatives | — | | | (2) | | | — | | | — | | | (2) | |
Interest rate derivatives | (5) | | | (60) | | | — | | | — | | | (65) | |
| $ | (6) | | | $ | (152) | | | $ | (19) | | | $ | 56 | | | $ | (121) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $26 million and $35 million as of December 31, 2021 and 2020, respectively.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as tax equity investments. Underwell as for those contracts that are not actively traded, the termsCompany uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these taxderivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
The following table reconciles the beginning and ending balances of the Company's financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Derivatives | | Interest Rate Derivatives | | |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | | | | | |
| | | | | | | | | | | | | | | | | |
Beginning balance | $ | 116 | | | $ | 97 | | | $ | 99 | | | $ | 62 | | | $ | 14 | | | $ | 10 | | | | | | | |
Changes included in earnings(1) | (43) | | | (10) | | | 10 | | | (43) | | | 48 | | | 4 | | | | | | | |
Changes in fair value recognized in OCI | (13) | | | — | | | (1) | | | — | | | — | | | — | | | | | | | |
Changes in fair value recognized in net regulatory assets | (118) | | | (17) | | | (26) | | | — | | | — | | | — | | | | | | | |
| | | | | | | | | | | | | | | | | |
Purchases | (76) | | | 5 | | | 6 | | | — | | | — | | | — | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Settlements | (34) | | | 41 | | | 9 | | | — | | | — | | | — | | | | | | | |
Transfers to Level 2 | 17 | | | — | | | — | | | — | | | — | | | — | | | | | | | |
| | | | | | | | | | | | | | | | | |
Ending balance | $ | (151) | | | $ | 116 | | | $ | 97 | | | $ | 19 | | | $ | 62 | | | $ | 14 | | | | | | | |
(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.
The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 49,762 | | | $ | 57,189 | | | $ | 49,866 | | | $ | 60,633 | |
(16)Commitments and Contingencies
Commitments
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 2027 and | | |
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | | $ | 2,475 | | | $ | 1,635 | | | $ | 1,422 | | | $ | 1,164 | | | $ | 1,054 | | | $ | 11,964 | | | $ | 19,714 | |
Construction commitments | | 1,329 | | | 831 | | | 776 | | | 87 | | | 4 | | | — | | | 3,027 | |
Easements | | 82 | | | 84 | | | 80 | | | 82 | | | 83 | | | 2,870 | | | 3,281 | |
Maintenance, service and other contracts | | 474 | | | 364 | | | 300 | | | 249 | | | 240 | | | 1,543 | | | 3,170 | |
| | $ | 4,360 | | | $ | 2,914 | | | $ | 2,578 | | | $ | 1,582 | | | $ | 1,381 | | | $ | 16,377 | | | $ | 29,192 | |
Fuel, Capacity and Transmission Contract Commitments
The Utilities have fuel supply and related transportation and lime contracts for their coal- and natural gas-fueled generating facilities. The Utilities expect to supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. The Utilities acquire a portion of their electricity through long-term purchases and exchange agreements. The Utilities have several power purchase agreements with renewable generating facilities that are not included in the table above as the payments are based on the amount of energy generated and there are no minimum payments. The Utilities also have contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to their customers.
MidAmerican Energy has long-term rail transportation contracts with BNSF Railway Company ("BNSF"), an affiliate company, and Union Pacific Railroad Company for the transportation of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities. For the years ended December 31, 2021, 2020 and 2019, $76 million, $90 million and $123 million, respectively, were incurred for coal transportation services, the majority of which was related to the BNSF agreement.
Construction Commitments
The Company's firm construction commitments reflected in the table above include the following major construction projects:
•PacifiCorp's costs associated with certain generating plant, transmission, and distribution projects.
•MidAmerican Energy's firm construction commitments primarily consisting of contracts for the repowering and construction of wind-powered generating facilities and solar-powered generating facilities and the settlement of AROs.
•Nevada Utilities' firm construction commitments consisting of costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada and certain other generating plant projects and costs associated with two additional solar photovoltaic facility projects. The first project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. Both facilities will be jointly owned and operated by Nevada Power and Sierra Pacific.
•AltaLink's investments in directly assigned transmission projects from the AESO.
Easements
The Company has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.
Maintenance, Service and Other Contracts
The Company has entered into equity capital contributionservice agreements related to its nonregulated wind-powered and solar-powered projects with third parties to operate and maintain the projects under fixed-fee operating and maintenance agreements. Additionally, the Company has various non-cancelable maintenance, service and other contracts primarily related to turbine and equipment maintenance and various other service agreements.
Legal Matters
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. Additionally, multiple insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the project sponsors2020 Wildfires that require contributions. are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.
Environmental Laws and Regulations
The Company has made contributions of $698 million, $403 millionis subject to federal, state, local and $584 millionforeign laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in 2018, 2017material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 respectively, pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
BHE, through a subsidiary, owns 50% of Electric Transmission Texas, LLC, which owns and operates electric transmission assets in the Electric Reliability Council of Texas footprint. BHE, through a subsidiary, owns 66.67% of Bridger Coal Companyamended Klamath Hydroelectric Settlement Agreement ("Bridger Coal"KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a coal miningprocess for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint venture that supplies coalapplication with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the Jim Bridger Nos. 1-4 generating facility. Bridger Coal is being accountedKRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for under the equity methodPacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are sharedagreement (the "MOA") with the joint venture partner. See Note 11 for discussionKRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of 2017 Tax Reform impactsthe KHSA. The agreement required the States, PacifiCorp and KRRC to equity earnings recordedfile a new license transfer application to remove PacifiCorp from the license for the year endedKlamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending.
As of December 31, 2017.2021, PacifiCorp's assets included $14 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $193 million over the next 10 years. Included in these estimates are commitments associated with the KHSA.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
(17) Revenue from Contracts with Customers
Restricted InvestmentsAltaLink
AltaLink is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing.
The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable, and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.
AltaLink's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act (Alberta) in respect of rates and terms and conditions of service. The Electric Utilities Act (Alberta) and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.
Under the Electric Utilities Act (Alberta), AltaLink prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides AltaLink with a reasonable opportunity to (i) earn a fair return on equity; and (ii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes (including deemed income taxes) associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. AltaLink's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.
The AESO is an independent system operator in Alberta, Canada that oversees the Alberta Interconnected Electric System ("AIES") and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. AltaLink and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.
The AESO determines the need and plans for the expansion and enhancement of the transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing the current and future transmission system capacity needs of market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally, the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.
Independent Power Projects
The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Walnut Ridge, Pinyon Pines I, Pinyon Pines II, Santa Rita, Independence, Gopher Creek, Flat Top, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Community Solar Gardens, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.
The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Marshall, Grande Prairie, Walnut Ridge, Independence, Pinyon Pines I and Pinyon Pines II independent power projects have obtained authority from the FERC to sell their power using market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines I, Pinyon Pines II, Solar Star 1, Solar Star 2, Topaz and Yuma independent power projects and power marketer CalEnergy, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2019 and an order accepting it was issued in March 2020. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2020 and an order accepting it was issued in December 2020. The Bishop Hill II and Walnut Ridge independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2020 and an order accepting it was issued in March 2021. The Marshall and Grande Prairie independent power projects and power marketer CalEnergy, LLC file together for market power study purposes in the FERC-defined Southwest Power Pool Region. The most recent triennial filing for the Southwest Power Pool Region was made in December 2021 and is awaiting FERC action.
The entire output of Jumbo Road, Santa Rita, Gopher Creek, Flat Top, Alamo 6, Pearl and Power Resources is within the ERCOT and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Light Company within the Hawaii electric grid, which is not a FERC-jurisdictional market and therefore, Wailuku does not require market-based rate authority.
EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utility's avoided cost.
Residential Real Estate Brokerage Company
HomeServices and its operating subsidiaries are regulated by the United States Consumer Financial Protection Bureau which enforces the Truth In Lending Act ("TILA"), the Equal Credit Opportunity Act ("ECOA") and the Real Estate Settlement Procedures Act ("RESPA"); by the United States Federal Trade Commission with respect to certain franchising activities; by the United States Department of Housing and Urban Development, which enforces the Fair Housing Act ("FHA"); and by state agencies where its subsidiaries operate. TILA and ECOA regulate lending practices. FHA prohibits housing-related discrimination on the basis of race, color, national origin, religion, sex, familial status, and disability. RESPA regulates real estate settlement services including real estate closing practices, lender servicing and escrow account practices and business relationships among settlement service providers and third parties to the transaction.
REGULATORY MATTERS
In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further information regarding the general regulatory framework.
PacifiCorp
Utah
In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million of deferred net power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to current rates. The UPSC approved the request in February 2021 for rates effective March 1, 2021.
In March 2021, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $2 million of deferred net power costs from customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflected a $36 million reduction, or 1.7% decrease compared to current rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain load related data reflected in the initial application. The updated recovery request reflects a $31 million reduction, or 1.5%, decrease compared to current rates. In January 2022, PacifiCorp filed an uncontested stipulation agreement providing for full recovery of the requested $7 million. The UPSC approved the stipulation agreement as filed in February 2022.
In August 2021, PacifiCorp filed an application with the UPSC for alternative cost recovery of a major plant addition to recover the incremental revenue requirement related to the delayed portions of the Pryor Mountain and TB Flats wind-powered generating facilities that are not currently reflected in rates from the last general rate case. PacifiCorp's request would result in a net decrease of $4 million, or 0.2%, in base rates effective January 1, 2022. Requested recovery of $7 million for the capital related cost is offset by $7 million related to forecast PTCs and $4 million in net power cost savings with actual PTCs and net power cost savings to be trued-up in the EBA. In December 2021, the UPSC concluded PacifiCorp's request did not qualify for recovery under the major plant additions statute and denied the application.
In August 2021, PacifiCorp filed an application with the UPSC for approval of its Electric Vehicle Infrastructure Program as provided for by Utah House Bill 396 ("HB 396"), Electric Vehicle Charging Infrastructure Amendments. The filing details how PacifiCorp proposes to invest the $50 million authorized by HB 396 to support the development of electric vehicle infrastructure in Utah. In November 2021, PacifiCorp reached a settlement stipulation with most of the intervening parties resolving all issues. The remaining intervening parties are not signatories but did not oppose the stipulation. The new program provides funding for both utility-owned charging equipment and make-ready infrastructure; establishes a new tariff for charging rates at PacifiCorp-owned stations, initially set at 45 cents per kilowatt-hour for the general public with a 40% discount for PacifiCorp's Utah customers; creates a new surcharge to collect $50 million over 10 years from Utah customers to fund the program; establishes annual reporting to the UPSC with a program review every three years; and extends the residential time-of-use pilot rates. The surcharge replaced the existing Sustainable Transportation and Energy Plan cost adjustment that expired on December 31, 2021. In December 2021, the UPSC approved the settlement stipulation, resulting in a decrease of $5 million, or 0.2%, compared to current rates effective January 1, 2022.
Oregon
In February 2020, PacifiCorp filed a general rate case and in December 2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind-powered generating facilities, new wind-powered generating facilities and certain other new investments that had not been placed in-service at the time of the filing. Additional compliance filings have been made to include investments in rates concurrent with when they were placed in-service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind-powered generating facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind-powered generating facility and the Pryor Mountain new wind-powered generating facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021. In July 2021, a deferral for resources not placed in-service by June 30, 2021 was filed for consideration in a future rate proceeding.
In July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The application requests an initial rate increase of $35 million, or 2.8%, effective January 1, 2022, to recover the incremental costs from those approved in the last general rate case.
In April 2021, PacifiCorp submitted its annual TAM filing in Oregon requesting an increase of $1 million, or 0.1%, effective January 1, 2022, based on forecast net power costs and loads for the calendar year 2022. In July 2021, PacifiCorp filed a reply with an amended net power costs which updated its 2022 TAM to a $2 million rate increase. In November 2021, the OPUC approved PacifiCorp's 2022 TAM, subject to adjustments, reducing PacifiCorp's requested net power cost amount and resulting in an overall annual rate decrease of approximately $15 million, or 1.2 %, effective January 1, 2022.
In May 2021, Oregon's governor signed Oregon House Bill 2165 requiring electric companies to collect funding to support and integrate transportation electrification. In July 2021, Oregon's governor signed Oregon House Bill 3141 addressing changes related to public purpose and energy efficiency rates. In November 2021, PacifiCorp filed an advice letter to address the legislative changes adopted in House Bills 2165 and 3141. In December 2021, the OPUC approved the advice filing. The filing resulted in an overall rate increase of approximately $5 million, or 0.4%, effective January 1, 2022.
In July 2021, Oregon's governor signed Oregon House Bill 2739 requiring electric companies to collect an additional $10 million per calendar year for low-income electric bill payment and crisis assistance beginning January 1, 2022. In November 2021, PacifiCorp filed an advice letter to revise the rates, and the OPUC approved the advice filing in December 2021. The filing resulted in an overall rate increase of $4 million, or 0.3%, effective January 1, 2022, representing PacifiCorp's share.
Wyoming
In September 2018, PacifiCorp filed an application for depreciation rate changes with the WPSC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities and removal of Cholla Unit 4. In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent written order in December 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application was held in July 2021. In September 2021, the WPSC approved in a bench decision PacifiCorp's application to defer depreciation expense incurred from January 1, 2021 through June 30, 2021 subject to certain offsetting cost savings during the relevant period. A final order is pending. The WPSC will address recovery of the deferred costs in a future general rate case.
In March 2020, PacifiCorp filed a general rate case with the WPSC which reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested a revision to the ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million, or 1.3%, and reflected an update to the rate mitigation measures for using 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and were completed in March 2021. In May 2021, the WPSC approved a $7 million base revenue requirement increase that includes the Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and rate design proposals to be offset by returning the remaining 2017 Tax Reform benefits to customers over the next three years. The WPSC also approved revisions to the ECAM to adjust the sharing band from 70/30 to 80/20 and to include PTCs within the mechanism. PacifiCorp's proposals for extended recovery of the depreciation of certain coal-fueled generation units and use of remaining 2017 Tax Reform benefits to buy down certain plant balances were denied. The WPSC decision resulted in an overall net decrease of 3.5% effective July 1, 2021. A final written order was issued in July 2021.
In April 2021, PacifiCorp filed its annual ECAM and REC and Sulfur Dioxide Revenue Adjustment Mechanism application with the WPSC requesting to refund $15 million of deferred net power costs and RECs to customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflects a 2.4% decrease compared to current rates. PacifiCorp requested an interim rate effective July 1, 2021, which was approved by the WPSC in June 2021. PacifiCorp filed an all-party stipulation in October 2021. A hearing on the stipulation was held in November 2021 during which the WPSC approved the all-party stipulation in a bench decision and the final order was issued in February 2022.
Washington
In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase had a requested effective date of January 1, 2022. In November 2021, PacifiCorp reached a proposed settlement with most of the parties, which includes an agreement to adjust the PTC rate in base rates and apply a production factor and to include a net power cost update as part of the compliance filing. A hearing was held in January 2022 and a WUTC decision is pending.
Idaho
In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020, a 1.1% decrease compared to current rates. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs, changes in RECs, and a resource tracking mechanism to match costs with the benefits of new wind and wind repowering projects until they are reflected in base rates. In May 2021, PacifiCorp updated the requested recovery to correct for certain load related data reflected in the initial application, and the IPUC approved recovery of $10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2021.
In May 2021, PacifiCorp filed a general rate case with the IPUC requesting a $19 million, or 7.0%, revenue requirement increase effective January 1, 2022. This is the first general rate case PacifiCorp has filed in Idaho since 2011. The rate case includes recovery of Energy Vision 2020 investments, the Pryor Mountain wind-powered generating facility, repowered Foote Creek, new investment in transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested recovery of the decommissioning and closure costs associated with the early retirement of Cholla Unit 4. PacifiCorp filed an all-party settlement with the IPUC in October 2021, resolving all issues in the case. The settlement provides an $8 million, or 2.9%, overall increase, which will be offset in part by a refund of deferred income tax savings over two years, resulting in a net increase of $4 million, or 1.4%. In December 2021, the IPUC issued an order approving the settlement with rates effective January 1, 2022.
California
California SB 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in March 2021 for which it received approval in July 2021.
In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $7 million, or 6.7%, decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. In March 2021, the CPUC approved the rate change related to GHG allowances and in November 2021, approved updated rates for energy costs as filed.
In August 2021, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application included a $5 million rate decrease associated with lower energy costs, partially offset by an increase of $3 million to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. PacifiCorp's application would result in a rate decrease of $2 million, or 1.9%, effective January 1, 2022. In January 2022, PacifiCorp filed an amended application, per CPUC direction, to reflect ECAC rates which had been approved since the original filing was made in August 2021. The amended application included an over $3 million rate increase associated with higher energy costs, as well as the previously sought increase of $3 million to recover GHG allowances. PacifiCorp's application would result in a rate increase of $7 million, or 6.6%. PacifiCorp anticipates interim approval of its GHG rates in March 2022 based on a settlement stipulation filed by the parties.
FERC Show Cause Order
On April 15, 2021, the FERC issued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain NERC reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of $42 million as a result of the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. In July 2021, PacifiCorp filed its answer to the FERC's show cause order denying the alleged violation of certain NERC reliability standards. The FERC Office of Enforcement staff replied in September 2021. A decision by the FERC is pending.
MidAmerican Energy
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all of Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy secured sufficient safe harbor equipment necessary to remain eligible for 60% PTCs under current tax law and has asked the IUB to issue a final decision on the application by October 2022 to allow MidAmerican Energy to construct Wind PRIME and place it in-service by the end of 2024.
Natural Gas Purchased for Resale
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the year ended December 31, 2021.
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law ensures MidAmerican Energy, as an incumbent electric transmission owner, has the legal right to construct, own and maintain transmission lines that have been approved by the MISO (or another federally registered planning authority) in MidAmerican Energy's service territory. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for construction that it intends to construct, own and maintain the electric transmission line. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the electric transmission line. Legal challenges have been brought against similar laws in other states, but courts that have ruled on such cases have upheld the states' laws. In October 2020, a lawsuit challenging the law was filed in Iowa by national transmission interests. The suit raises issues specific to Iowa law, and the State of Iowa is defending the law in the suit. MidAmerican Energy intervened in the suit and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021, and the national transmission interests appealed. The parties are in the process of briefing the court. A date for oral arguments has not been set and is not expected until third quarter 2022.
Renewable Subscription Program
In December 2020, MidAmerican Energy filed with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customers with the opportunity to meet their future energy growth above baseline levels with renewable energy from specific additions to MidAmerican Energy wind-powered generation and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the RSP, MidAmerican Energy would own the facilities, retain PTCs and other tax benefits associated with the facilities and include all revenues and costs from the program in its Iowa-jurisdictional results of operation, but renewable attributes from the facilities would be specifically assigned to subscribing customers. In June 2021, the IUB issued an order rejecting the RSP and, in July 2021, issued an order denying MidAmerican Energy's request for reconsideration thereof and affirming its June 2021 order. In the July order, the IUB expressed its view that the RSP-related generating facilities and associated PTCs, costs and revenues must be removed from MidAmerican Energy's revenue sharing calculations. In June 2021, the IUB issued an order opening a docket to review MidAmerican Energy's revenue sharing calculations. That docket remains open.
NV Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Reviews
In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2020, the PUCN issued a final order directing Nevada Power to continue the earning sharing mechanism subject to any modifications made to the earning sharing mechanism pursuant to an alternative ratemaking ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory rate review. The new rates were effective on January 1, 2021.
Price Stability Tariff
In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option for renewable resources. The CPST provides for an energy rate that would replace the BTER and DEAA. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and an updated CPST with the PUCN. The enrollment period for the tariff has ended with no customers having enrolled.
Natural Disaster Protection Plan
The Nevada Utilities submitted their initial NDPP to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. The Bureau of Consumer Protection filed a petition for judicial review with the district court in November 2020.In December 2020, the PUCN issued a second modified final order approving the NDPP, as modified, and reopened its investigation and rulemaking on SB 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an order is expected in 2022. In March 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. The Nevada Utilities filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, the Nevada Utilities and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
SB 448
SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage, and accelerate transportation electrification within the state of Nevada. In September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of high-voltage transmission infrastructure, Greenlink North among others, that will be placed into service no later than December 31, 2028, and requires the IRP to include at least one scenario that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. The plan establishes requirements for the contents of the transportation electrification investment as well as requirements for review, cost recovery and monitoring. The plan covers an initial period beginning January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN issued an order granting the application and accepting the Economic Recovery Transportation Electrification Plan with some modifications. The PUCN opened rulemakings to address other regulations that resulted from SB 448. These rulemakings are ongoing.
ON Line Temporary Rider ("ONTR")
In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR with corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a result of the ON Line cost reallocation as well as the related on-going reallocated revenue requirement. Sierra Pacific's application would, if approved by the PUCN as filed, result in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022. In November 2021, intervening parties filed motions to dismiss the filing which were denied by the PUCN in December 2021. A hearing with the PUCN for the application was held in February 2022 and an order is expected in the first quarter of 2022.
Northern Powergrid Distribution Companies
GEMA, through the Ofgem is undertaking its scheduled review of the electricity distribution price control, to put in place a new price control at the end of the current period, which ends March 2023.
The new price control ("ED2") will run for five years, from April 2023 to March 2028. In December 2020 and March 2021, GEMA published its decision on the methodology it will use to set ED2. This confirmed that Ofgem will maintain many aspects of the current price control and that the changes being made will generally follow the template that was set by the price controls implemented in April 2021 for transmission and gas distribution in Great Britain. Specific changes include some new service standard incentives and mechanisms to adjust cost allowances in specific circumstances, while others will be discontinued, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds.
Ofgem published a working assumption of 4.65% for the allowed cost of equity (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs, CPIH). When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, this working assumption is approximately two percentage points lower than the current cost of equity for electricity distribution. Ofgem will set a final value in its determinations in late 2022.
In December 2021, Northern Powergrid published and filed its business plan with Ofgem, setting out its detailed approach for 2023-2028 including the cost allowances this approach would require. Ofgem is expected to publish draft determinations of the new price control in mid-2022 with final determinations expected in late 2022.
BHE Pipeline Group
BHE GT&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of approximately $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of approximately $4 million and a decrease in annual depreciation expense of approximately $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.
Northern Natural Gas
In January 2019, FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC Section 5 order, Northern Natural Gas filed a cost and revenue study in April 2019. In July 2019, Northern Natural Gas filed a Section 4 rate case requesting increases in its transportation and storage rates. In January 2020, the FERC approved Northern Natural Gas' filing to implement its interim rates subject to refund, effective January 1, 2020. In June 2020, a settlement agreement was filed with the FERC, resolving the Section 5 investigation and Section 4 rate case and providing for increased service rates and depreciation rates. Market Area transportation reservation rates increased 28.5% and storage reservation rates increased 67.0% from the rates that were in effect in 2019. Depreciation rates are 2.3% for onshore transmission plant, 2.95% for LNG storage plant, 13.0% for intangible plant, and 2.75% for general plant. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2022, subject to certain exceptions, as well as provides for minimum annual maintenance capital spending. The settlement rates were implemented May 1, 2020, and the Company's provision for rate refunds for January 2020 through April 2020 totaled $69 million. The FERC approved the settlement in September 2020, and rate refunds to customers were processed in early October 2020.
BHE Transmission
AltaLink
Tariff Refund Application
In January 2021, driven by the pandemic and economic shutdown that negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consisted of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation.
In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 customer tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provided Alberta customers with immediate tariff relief in 2021. The approved 2021 tariff refund included a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 were proposed in AltaLink's 2022-2023 GTA.
2019-2021 General Tariff Application
In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide a further tariff reduction over the three-year period by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In April 2019, AltaLink filed an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.
In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the three-year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023.
In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.
In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership. The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.
In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year-over-year increase of approximately 2% in 2022 and 2023 revenue requirements. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively.
In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. The amended application requested the approval of transmission tariffs of C$820 million and C$843 million for 2022 and 2023, respectively. In November 2021, the AUC approved the 2022 interim refundable transmission tariff at C$57 million per month effective January 2022.
In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. The AUC approved a two-year total revenue requirement of C$1.7 billion as compared to AltaLink's requested revenue requirement of C$1.8 billion. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta.
2022 Generic Cost of Capital Proceeding
In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding considered the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the AUC requested participants to submit comments that addressed the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.
In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there was insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.
In March 2021, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta customers.
2023 Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the 2023 generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. Due to ongoing capital market uncertainties related to COVID-19, the AUC is considering extending the 2022 approved cost of capital parameters, of 8.5% return on equity and 37% deemed equity ratio, to 2023. The AUC intends to issue a decision on the first stage by March 31, 2022. With respect to the second stage, the AUC plans to commence the 2024 GCOC proceeding to establish a formula-based approach in the third quarter of 2022 and to conclude in the second quarter of 2023.
2019 Deferral Accounts Reconciliation Application
In October 2020, AltaLink filed its application with the AUC, which included 10 projects with total gross capital additions of C$129 million, including applicable AFUDC. In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128 million of the gross capital project additions. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and annual structure payments as filed. AltaLink filed its compliance filing in April 2021. In May 2021, the AUC issued its decision approving the compliance filing as filed.
BHE U.S. Transmission
A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review scheduled for no later than February 1, 2023. In January 2021, the Public Utilities Commission of Texas ("PUCT") approved ETT's request to suspend a base regulatory rate review filing scheduled for February 2021. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007. In June 2018, the PUCT approved ETT's application to reduce its transmission revenue by $28 million to reflect the lower federal income tax rate due to 2017 Tax Reform with the amortization of excess accumulated deferred federal income taxes expected to be addressed in the next base rate case.
ENVIRONMENTAL LAWS AND REGULATIONS
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The Company has cumulative investments in (i) owned wind, solar and geothermal generating facilities of $30.1 billion and (ii) wind tax equity investments of $5.9 billion. The Company plans to spend an additional $7.8 billion on the construction of renewable generating facilities and repowering certain existing wind-powered generating facilities through 2024. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's renewable generation-related capital expenditures.
Climate Change
In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of GHG emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders' Summit held in April 2021, President Biden announced new climate goals to cut GHG emissions 50%-52% economy-wide by 2030 compared to 2005 levels and to reach 100% carbon pollution-free electricity by 2035.
GHG Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fueled with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred, and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. The EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, the EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. The EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule on April 5, 2021.
Affordable Clean Energy Rule
In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the United States Supreme Court in February 2016 while litigation proceeded. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan, which was intended to achieve an overall reduction in carbon dioxide emissions from existing fossil-fueled electric generating units of 32% below 2005 levels. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule, which fully replaced the Clean Power Plan. In the Affordable Clean Energy rule, the EPA determined that the best system of emissions reduction for existing coal-fueled generating facilities is limited to actions that can be taken at a point source facility, specifically heat rate improvements and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. States have until July 2022 to submit compliance plans to the EPA. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the United States Supreme Court agreed to hear an appeal of that decision. Arguments in the case will be held February 28, 2022, and a decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act is expected by June 2022. Until litigation is exhausted and the EPA indicates its course of action in response to this decision, the full impacts on the Registrants cannot be determined. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including generating facility efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advanced customer energy efficiency programs.
New Source Performance Standards for Methane Emissions
In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution reinstated the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA proposed rules that would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposals would expand and strengthen emissions reduction requirements for new, modified and reconstructed oil and natural gas sources and would require states to reduce methane emissions from existing sources nationwide. The EPA took comment on the proposed rules through January 31, 2022. The EPA intends to issue a supplemental proposal in 2022, including draft regulatory text, and plans to finalize the rules by the end of 2022. Until the rules are finalized, the relevant Registrants cannot determine the full impacts of the proposed rule.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:
•In June 2013, Nevada SB 123 was signed into law. Among other things, SB 123 and regulations thereunder required Nevada Power to file with the PUCN an emissions reduction and capacity replacement plan by May 1, 2014. In May 2014, Nevada Power filed its emissions reduction capacity replacement plan. The plan provided for the retirement or elimination of 300 MWs of coal-fueled generating capacity by December 31, 2014, another 250 MWs of coal-fueled generating capacity by December 31, 2017, and another 250 MWs of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also sets forth the expected timeline and costs associated with decommissioning coal-fueled generating units that will be retired or eliminated pursuant to the plan. The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by Nevada Power. The PUCN may approve variations to Nevada Power's resource plans relative to requirements under SB 123. Refer to Nevada Power's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the ERCR Plan.
•Under the authority of California's Global Warming Solutions Act, which includes a series of policies aimed at returning California GHG emissions to 1990 levels by 2020, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations were imposed on entities beginning in 2013. PacifiCorp is subject to the cap-and-trade program as a retail service provider in California and an importer of wholesale energy into California. In 2015, California's governor issued an executive order to reduce emissions to 40% below 1990 levels by 2030 and 80% by 2050. In September 2016, California SB 32 was signed into law establishing GHG emissions reduction targets of 40% below 1990 levels by 2030.
•The states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electricity generating resources. Under the laws in California and Oregon, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. In September 2018, the Washington Department of Commerce amended the emissions performance standards to provide that GHG emissions for base load electricity generating resources must not exceed 925 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.
•In September 2016, the Washington Department of Ecology issued a final rule regulating GHG emissions from sources in Washington. The rule regulates GHG including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride beginning in 2017 with three-year compliance periods thereafter (i.e., 2017-2019, 2020-2022, etc.). Under the rule, the Washington Department of Ecology established GHG emissions reduction pathways for all covered entities. Covered entities may use emission reduction units, which may be traded with other covered entities, to meet their compliance requirements. PacifiCorp's resource that is covered under the rule includes the Chehalis generating facility, which is a natural gas combined-cycle generating facility located in Washington state. PacifiCorp received its baseline emission order on December 17, 2017, which specified the emission reduction requirements for the Chehalis generating facility every three years beginning in 2017. The reduction requirements average 1.7% per year. However, the Washington Department of Ecology suspended the compliance obligations of the Clean Air Rule after a Thurston County Superior Court judge ruled the state lacks authority to mandate reductions from indirect emitters. On January 16, 2020, the Washington Supreme Court affirmed that the rule limits the applicability of emission standards to actual emitters and cannot be expanded to non-emitters. The court also found that the rule itself is severable, so that the Washington Department of Ecology may continue to enforce the rule as it applies to emitters. The case was remanded for further proceedings. Pending further action by the lower court, the rule itself remains suspended, but entities subject to the rule are required to continue reporting emissions.
•The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to cap and reduce power sector GHG emissions in 11 Eastern states, required, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. Following a program review in 2012, the nine Regional Greenhouse Gas Initiative states implemented a new 2014 cap which was approximately 45% lower than the 2012-2013 cap. The cap is reduced each year by 2.5% from 2015 to 2020. In December 2017, an updated model rule was released by the Regional Greenhouse Gas Initiative states which includes an additional 30% regional cap reduction between 2020 and 2030.
•On May 7, 2019, Washington's governor signed into law the Clean Energy Transformation Act ("CETA") (SB 5116), which requires utilities to eliminate coal generation from Washington customers' allocation of electricity and requires all sales of electricity to Washington retail electric customers to be greenhouse gas neutral by 2030, and non-emitting and electric generation from renewable resources to supply 100% of retail sales by 2045. Electric utilities must also eliminate from rates coal-fueled resources by December 31, 2025. PacifiCorp submitted its first Clean Energy Implementation Plan, demonstrating how it plans to meet the targets established in the law, on December 30, 2021.
•On July 27, 2021, Oregon's governor signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baseline of the average of 2010, 2011 and 2012 emissions and requires utilities to meet the following reductions from that baseline: 80% by 2030, 90% by 2035 and 100% by 2040. The law also requires by 2030 at least 10% of the aggregate electrical capacity of utilities to be comprised of small-scale renewable resources with a capacity of 20 MWs or less by 2030. No earlier than second quarter 2023, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets. While the regulatory framework is still being developed, PacifiCorp anticipates coordinating the submittals of its clean energy plan and IRP in 2023.
•On May 17, 2021, the state of Washington passed the Climate Commitment Act (SB 5126), which creates an economy-wide cap-and-trade program to reduce GHG emissions. Under the Climate Commitment Act, the Washington Department of Ecology must establish progressively declining annual allowance budgets for emissions of GHG beginning January 1, 2023. PacifiCorp is subject to the Climate Commitment Act as an importer and generator of electricity in Washington.
•Illinois enacted the Climate and Equitable Jobs Act in September 2021, a wide-ranging energy omnibus bill touching on nearly all aspects of state energy policy. Among other things, the act codifies Illinois' policy to rapidly transition to 100% clean energy by 2050, which is achieved, in part, by preserving existing nuclear generation, doubling investment in wind and solar projects, and investigating alternative technologies, such as energy storage.
•Wisconsin, through a 2019 executive order, established the Wisconsin Office of Sustainability and Clean Energy, which is charged with achieving a goal of 100% carbon-free electricity by 2050. To assist reaching that goal, Wisconsin's governor also established the Governor's Task Force on Climate Change, to solicit stakeholder input and develop policy recommendations to meaningfully mitigate and adapt to the effects of climate change. Aggressive utility carbon reduction goals are among the task force's recommendations, including a goal of reducing net energy-sector carbon emissions to 100% below 2005 levels by 2050.
•Minnesota enacted an economy-wide requirement to reduce GHG emissions at least 80% below 2005 levels by 2050. The state codified a preference for using clean energy resources to meet its electricity demand, and that preference served as a basis for the state's largest utilities to commit to 100% carbon-free electricity by 2050. Minnesota's governor recently accelerated the state's timeline by proposing a standard requiring utilities to provide 100% carbon-free electricity by 2040, a decade earlier than current commitments. The accelerated standard is currently being considered by the state's legislature.
Renewable Portfolio Standards
Each state's RPS described below could significantly impact the relevant Registrant's consolidated financial results. Resources that meet the qualifying electricity requirements under each RPS vary from state to state. Each state's RPS requires some form of compliance reporting, and the relevant Registrant can be subject to penalties in the event of noncompliance. Each Registrant believes it is in material compliance with all applicable RPS laws and regulations.
In 1983, Iowa became the first state in the United States to adopt a RPS requiring the state utilities to own or to contract for a combined total of 105 MWs of renewable generating capacity and associated energy production. The IUB allocated the 105-MW requirement between the two utilities in Iowa based on each utility's percentage of their combined estimated Iowa retail peak demand in 1990 resulting in MidAmerican Energy being allocated a RPS requirement of 55.2 MWs. The utility must meet its RPS obligation by either owning renewable energy production facilities located in Iowa or entering into long-term contracts to purchase or wheel electricity from renewable production facilities located in the utility's service area.
Since 1997, NV Energy has been required to comply with a RPS. In November 2020, Nevada voters approved a constitution amendment that requires the state to obtain at least half its electricity from renewable sources by 2030. Beginning in 2022, the state must get 22% of its electricity from renewable sources. That percentage is increased incrementally over eight years up to the 50% threshold by 2030. The state's previous RPS required utilities to obtain 25% of their electricity from renewable sources by 2025.
Utah's Energy Resource and Carbon Emission Reduction Initiative provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere within the WECC, and RECs can be used.
The Oregon Renewable Energy Act ("OREA") provides a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the law, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, and 20% in 2020 through 2024. In March 2016, Oregon SB 1547-B, the Clean Electricity and Coal Transition Plan, was signed into law. SB 1547-B requires coal-fueled resources be eliminated from Oregon's allocation of electricity by January 1, 2030 and increases the current RPS target from 25% in 2025 to 50% by 2040. SB 1547-B also implements new REC banking provisions, as well as the following interim RPS targets: 27% in 2025 through 2029, 35% in 2030 through 2034, 45% in 2035 through 2039, and 50% by 2040 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause (the RAC) to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.
Washington's Energy Independence Act establishes a renewable energy target for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020 and each year thereafter. In April 2013, Washington SB 5400 was signed into law. SB 5400 expands the geographic area in which eligible renewable resources may be located to beyond the Pacific Northwest, allowing renewable resources located in all states served by PacifiCorp to qualify. SB 5400 also provides PacifiCorp with additional flexibility and options to meet Washington's renewable mandates. Washington's recently enacted CETA, among other things, requires Washington utilities to be carbon neutral by January 1, 2030 and institutes a planning target of 100% non-emitting generation by 2045. Electric utilities must also eliminate from rates coal-fueled resources by December 31, 2025.
The California RPS required all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020. In October 2015, California SB 350 became law and increased the RPS target to 50% by December 31, 2030. The state's RPS was further expanded in September 2018, when California SB 100, the 100 Percent Clean Energy Act of 2018 was signed into law. In addition to requiring retail sellers to meet a RPS target of 60% by 2030, SB 100 enabled a longer-term planning target for 100% of total California retail sales to come from eligible renewable energy resources and zero-carbon resources by December 31, 2045. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three product content categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers.
Clean Air Act Regulations
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.
On June 4, 2018, the EPA published final ozone designations for much of the United States. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. The EPA must finalize the proposed rules by December 15, 2022. In addition, the EPA must, by December 15, 2022, approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. Also in January 2022, the EPA initiated interagency review of a new rule to address "good neighbor" SIP provisions. While the interagency review is not yet complete and the proposed rule is not available for public comment, the EPA has indicated the action would apply in certain states for which the EPA has either disapproved a "good neighbor" SIP submission or has made a finding of failure to submit such a plan for the 2015 ozone NAAQS. The action would determine whether and to what extent ozone-precursor emissions reductions are required to eliminate significant contribution or interference with maintenance from upwind states that are linked to air quality problems in other states for the 2015 standard. Until the EPA takes final action consistent with this decree, impacts to the relevant Registrants cannot be determined.
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 100 parts per billion. In February 2012, the EPA published final designations indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide NAAQS. On April 6, 2018, the EPA issued a decision to retain the 2010 nitrogen dioxide NAAQS without revision.
In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO2 NAAQS without revision.
The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations required the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate) are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.
In December 2012, the EPA finalized more stringent fine particulate matter NAAQS, reducing the annual standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. The EPA did not set a separate secondary visibility standard, choosing to rely on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014, the EPA issued final area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the relevant Registrant operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the relevant Registrant does not anticipate that any impacts of the revised standard will be significant. In December 2020, the EPA finalized its decision to retain, without revision, the existing primary and secondary standards for particulate matter. In June 2020, the EPA proposed a determination of attainment for the 2006 24-hour fine particulate matter for Salt Lake City and Provo, Utah, serious nonattainment areas. The determination is based upon quality-assured, quality controlled and certified ambient air monitoring data showing that the area has attained the 2006 standard based on the 2017-2019 monitoring. The comment period for the proposal ended in August 2020. In October 2021, the EPA issued a draft policy assessment for reconsideration on the 2020 particulate matter determination and accepted comments through December 2021. Until the rule and its reconsideration are finalized, the relevant Registrants cannot determine the impact on their operations.
In December 2014, the Utah SIP for fine particulate matter was adopted by the Utah Air Quality Board. PacifiCorp's Lake Side, Lake Side 2, Gadsby Steam and Gadsby Peakers generating facilities operate within nonattainment areas for fine particulate matter; however, the SIP did not impose significant new requirements on PacifiCorp's impacted generating facilities, nor did the EPA's comments on the Utah SIP identify requirements for PacifiCorp's existing generating facilities that would have a material impact on its consolidated financial results.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012 and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.
In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112, reaffirming its determination made in the 2016 Supplemental Finding that it was appropriate and necessary to regulate hazardous air pollutants while expanding the rationale supporting that conclusion. The EPA also proposed to retain the 2020 risk and technology review for MATS. The 2020 risk and technology review found that current standards are protective of human health with an adequate margin of safety and that there were no developments in practices, processes or standards warranting a revision of the standard. The EPA requests comments with information regarding technology and fleet emissions performance to inform any future action related to the risk and technology review. Any additional review of the risk and technology review will be separate from this proposal. Impacts from the rule as proposed are expected to be minimal. However, until the agency takes final action on the proposal, the relevant Registrants cannot fully determine the effects of the changes to the MATS rule.
In March 2020, the D.C. Circuit issued an opinion in Chesapeake Climate Action Network v. EPA regarding consolidated challenges to the EPA's startup and shutdown provisions contained in the 2012 MATS rule. The MATS rule's provisions governing startup and shutdown require electric generating units comply with work practice standards as opposed to numerical limits during these periods. The EPA denied petitions for reconsideration of these provisions in 2016 and environmentalists challenged this denial. The D.C. Circuit vacated the reconsideration denials, remanding the petition to the EPA for further action. The court did not make a determination on the merits of the arguments concerning the EPA's legal authority to set work practice standards. The existing work practice standards and the alternate definition for when startup ends continue to be applicable. Until the EPA finalizes action to respond to the court's order, the relevant Registrants cannot fully determine the impacts of the remand.
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.
The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit Court. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit Court issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from generating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at generating facilities in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021, a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and BHE Renewables operates natural gas-fueled generating facilities in Texas, Illinois and New York, which are subject to the CSAPR. MidAmerican Energy has installed emissions controls at its coal-fueled generating facilities to comply with the CSAPR and may purchase emissions allowances to meet a portion of its compliance obligations. The cost of these allowances is subject to market conditions at the time of purchase and historically has not been material. MidAmerican Energy believes that the controls installed to date are consistent with the reductions to be achieved from implementation of the rule. None of PacifiCorp's, Nevada Power's or Sierra Pacific's generating facilities are subject to the CSAPR. However, in a Notice of Data Availability published in the January 6, 2017 Federal Register, the EPA provided preliminary estimates of which upwind states may have linkages to downwind states experiencing ozone levels at or exceeding the 2015 ozone NAAQS of 70 parts per billion, and, using similar methodology to that in the CSAPR, indicated that Utah and Wyoming could have an obligation under the "good neighbor" provisions of the Clean Air Act to reduce NOx emissions. Until such time as a rule is finalized, the relevant Registrants cannot determine whether additional action may be required.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions ("CAMX") dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon generating facility federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington generating facilities. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation. After review of the rule by the Biden administration, the EPA determined it would defend the rule and briefing in the case occurred in January and February 2022. A date for oral arguments has not been scheduled.
The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The EPA, United States Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement. The EPA did not proceed with final approval of the settlement agreement for Wyodak and is currently engaged with Wyoming and PacifiCorp concerning alternative paths for resolution. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit allowing Naughton Unit 3 to operate on coal through 2017 and providing for natural gas conversion of the unit in 2018. In 2017, the department approved an extension of the compliance date for Naughton Unit 3 to align with the requirements of the Wyoming SIP extending the requirement to cease coal firing to no later than January 30, 2019. The EPA issued final approval of the Wyoming SIP, including the Naughton Unit 3 gas conversion, on March 21, 2019. PacifiCorp removed the unit from coal-fueled service on January 30, 2019 and completed the gas conversion in August 2020. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SCR, to be replaced with permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the four Jim Bridger units and submitted a regional haze SIP revision to the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) of the Clean Air Act, allowing the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took comment on the proposal through February 17, 2022. On February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp under Sections 201 and 209(a) of the Wyoming Environmental Quality Act, resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must convert both units to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4.
The state of Colorado regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2017 and 2019 IRPs.
Until the EPA takes final action in each state and decisions have been made in the pending appeals, PacifiCorp cannot fully determine the impacts of the Regional Haze Rule on its respective generating facilities.
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014 and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp and MidAmerican Energy are assessing the options for compliance at their generating facilities impacted by the final rule and will complete impingement and entrainment studies. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The costs of compliance with the cooling water intake structure rule cannot be fully determined until the prescribed studies are conducted and the respective state environmental agencies review the studies to determine whether additional mitigation technologies should be applied. If PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific do not utilize once-through cooling water intake or discharge structures at any of their generating facilities. All of the Nevada Power and Sierra Pacific generating stations are designed to have either minimal or zero discharge; therefore, they are not impacted by the §316(b) final rule.
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally promulgated guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal with the new limits to be met as soon as possible, beginning November 1, 2018 and fully implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review and requested the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018 and on September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. In a separate action, on April 12, 2019, the Fifth Circuit Court of Appeals vacated two aspects of the final effluent limitation guidelines, concerning discharge limits for (1) legacy wastewater from ash transport or treatment systems and (2) combustion residual leachate from landfills or settling ponds. The Fifth Circuit found that the EPA's own data did not support the agency's conclusion that impoundments were the best technology available for these two waste streams. The EPA must now complete a new effluent limitation guideline for these discharge limits. On November 22, 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule was finalized in October 2020 and took effect December 14, 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. The rule does not address the wastestreams at issue in the Fifth Circuit Court of Appeal's April 2019 decision. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025.
In April 2014, the EPA and the United States Army Corps of Engineers ("Corps of Engineers") issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but was appealed in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized September 12, 2019. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. On January 23, 2020, the EPA and the Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, which took effect 60 days after it was published in the Federal Register, redefines what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act is considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. On June 9, 2021, the EPA and the Corps of Engineers announced their intention to again revise the definition of "waters of the United States." After reviewing the Navigable Waters Protection Rule in accordance with Executive Order 13990, the agencies determined that the rule significantly reduced clean water protections. The agencies announced their intention to restore the clean water protections that were in place prior to the implementation of the "waters of the United States" rule in 2015. On August 30, 2021, the United States District Court for the District of Arizona vacated the Navigable Waters Protection Rule and the agencies quickly announced that they would no longer implement the rule nationwide. As a result, the agencies are relying on the pre-2015 regulatory definition of "waters of the United States" until they promulgate a new definition. Projects that are already permitted under the Navigable Waters Protection Rule and those that received an approved jurisdictional determination in reliance on the rule may continue to rely on those authorizations until they expire. Until the agencies take final action to update the definition of "waters of the United States," impacts to the relevant Registrants cannot be determined.
In April 2020, the United States Supreme Court established a trustnew test for Clean Water Act jurisdiction in County of Maui, Hawaii v. Hawaii Wildlife Fund, finding that the statute can cover discharges of contaminated groundwater in certain circumstances. The United States Supreme Court outlined a seven-factor test to determine whether discharges conveyed through groundwater to surface water are "functionally equivalent" to direct discharges, finding that the time it takes for pollutants to travel through groundwater and the distance traveled are the two most important factors in the test. The United States Supreme Court remanded County of Maui, Hawaii to the Ninth Circuit Court of Appeals for further adjudication, which subsequently remanded the case to the district court to determine whether additional discovery is needed before applying the new seven-factor test. The EPA finalized guidance January 14, 2021, implementing County of Maui, Hawaii. The EPA utilized the United States Supreme Court's seven factors, plus an additional factor for the design and performance of the system or facility from which the pollutant is reached, to determine whether pollutants that reach surface waters after traveling through groundwater are a "functional equivalent" to a direct discharge that require a permit. Until the functional equivalent test and guidance are applied by the courts, the Registrants cannot determine the impact of this case on their operations.
In April 2020, the United States District Court of the District of Montana vacated nationwide permit 12, which provides an expedited route for projects like oil and gas pipelines and utility lines to achieve compliance with the Clean Water Act, finding that the Corps of Engineers, which implements the nationwide permit program, failed to conduct necessary programmatic consultation of nationwide permit 12 under the Endangered Species Act. The district court's vacatur, which was subsequently limited just to the Keystone XL pipeline project, the subject of the initial lawsuit, is on appeal to the Ninth Circuit Court of Appeals. On January 13, 2021, the Corps of Engineers finalized a rule modifying its nationwide permit program for certain activities affecting waters of the United States. The final rule restructures the nationwide permit program for utility lines by splitting the existing nationwide permit 12 into three separate nationwide permits – one for oil and gas, including pipelines; one for electrical and telecommunications; and one for water/sewer and other utilities. The Corps of Engineers included a biological assessment for the final rule but did not conduct a formal Endangered Species Act consultation in connection with reissuance of the nationwide permits. The Corps of Engineers reissued and revised 12 of 52 and added four new nationwide permits, which will be effective for a period of five years. The remaining nationwide permits are scheduled for renewal in advance of expiration in 2022. Until the nationwide permit challenges are fully litigated, the Registrants cannot determine the impact of this case on their operations.
Coal Combustion Byproduct Disposal
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the RCRA. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports was posted to the respective Registrant's coal combustion rule compliance data and information websites in March 2018. Based on the results in those reports, additional action may be required under the rule.
At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit on November 20, 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. On August 21, 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to the EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held the EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, on March 15, 2018, issued a proposal to address provisions of the final CCR rule that were remanded back to the agency on June 14, 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of CCR units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The EPA finalized the first phase of the CCR rule amendments on July 30, 2018, with an effective date of August 28, 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 proposal modifies the definition of "beneficial use" by replacing a mass-based threshold with new location-based criteria for triggering the need to conduct an environmental demonstration; establishes a definition of "CCR storage pile" to address the temporary storage of CCR on the ground, depending on whether the material is destined for disposal or beneficial use; makes certain changes to the rule's annual groundwater monitoring and corrective action reports to make it easier for the public to see and understand the data contained within the reports; modifies the requirements related to facilities' publicly available CCR rule websites to make the information more readily available; and establishes a risk-based groundwater monitoring protection standard for boron in the event the EPA decides to add boron to Appendix IV in the CCR rule. The EPA accepted comments on the Phase 2 proposal through October 15, 2019. On December 22, 2020, the EPA released a notice of data availability relating to the Phase 2 proposal to revise the CCR rule's definition of beneficial use and provisions governing piles of CCR on- and off-site prior to beneficial use. The new information presented by the notice includes data and information the EPA received during the comment period on the Phase 2 proposal. The EPA accepted comment on the notice of data availability through February 22, 2021. The EPA has not announced an anticipated timeline for completing the Phase 2 rule. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The proposal would require permits for all CCR units in states that do not have an EPA-approved CCR program. The proposal would establish individual, general and permit-by-rule permits; a tiered schedule for applications to prioritize permits for high-hazard potential CCR units; and postpone timelines for permit applications for all other CCR units. The EPA has not announced an anticipated timeline for completing the federal CCR permit rule. In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. Issues identified by the EPA include the definition of a legacy impoundment, information on the universe of legacy impoundments, the types of regulatory requirements that should apply to legacy impoundments, and the EPA's regulatory authority to regulate legacy impoundments under RCRA subtitle D. The EPA accepted comment on the advanced notice through February 12, 2021. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule was finalized in August 2020 and establishes a new deadline of April 11, 2021, by which all unlined surface impoundments (including clay lined impoundments that do not otherwise meet the definition of "lined") must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. In addition to these closure deadline provisions, the Part A rule also finalized changes to the CCR rule's annual groundwater monitoring and corrective action reports and modified requirements related to CCR rule compliance websites initially proposed in the Phase 2 rule. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton facility and ash pond and submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule. In December 2020, the EPA finalized its Holistic Approach to Closure: Part B rule ("Part B rule"), which establishes procedures for owners and operators of unlined ash ponds to demonstrate that the liner systems or underlying soils for these units perform as well as the liner criteria in the CCR rule. Additional provisions included in the proposed rule but not finalized, including the use of CCR in closure activities and allowing for the completion of groundwater corrective action during the post-closure care period, will be addressed in future rulemakings. As finalized, none of the relevant Registrants anticipate exercising the provisions of the Part B rule.
Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' CCR permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Using that guidance, the state of Oklahoma applied for EPA approval of its state program, and, on June 28, 2018, the EPA's approval of the application was published in the Federal Register. Environmental groups, including Waterkeeper Alliance and the Sierra Club, filed suit in the D.C. Circuit on September 26, 2018, alleging that the EPA unlawfully approved Oklahoma's permit program. This suit also incorporates claims first identified in a July 26, 2018 notice of intent to sue that alleged the EPA failed to perform nondiscretionary duties related to the development and publication of minimum guidelines for public participation in the approval of state permit programs for CCR. To date, none of the states in which the Registrants operate has applied for EPA approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required PacifiCorp to submit permit applications for two of its landfills by March 2017. It is anticipated that the state of Utah will apply for EPA approval of its CCR permit program prior to the end of 2021. In 2019, the state of Wyoming proposed to adopt state rules which incorporate the final federal rule by reference. It is anticipated that Wyoming will finalize its rule and seek the EPA's approval to implement a state permit program in 2021.
Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.
On January 20, 2021, President Biden issued an executive order on climate change which also required review of actions taken over the preceding four years that were harmful to "public health, environment, unsupported by the best available science, or otherwise not in the national best interest." The order included a non-exhaustive list of regulatory actions to be reviewed by the issuing agencies, including New Source Performance Standards for the power sector and the oil and gas sector, rescission of the Clean Power Plan, particulate matter and ozone NAAQS, steam electric effluent limitation guidelines, waters of the United States, reissuance of nationwide permits, and the phase one, part one and holistic approach to closure: parts A and B under the CCR rule. In addition, the Biden administration issued a regulatory freeze memorandum that prohibits submission of rules and guidance documents to the Federal Register without direct review, requires immediate withdrawal of rules and guidance documents submitted to the Federal Register but not yet published, and, for rules and guidance documents published but not yet having taken effect, consideration of a 60-day delay and possible additional comment period. Until the issuing agency completes its review and takes final action consistent with these directives, the relevant Registrant cannot determine whether additional action under any of these rules will be necessary.
Other
Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:
•The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Certain Registrants have been identified as potentially responsible parties in connection with certain disposal sites. The relevant Registrants have completed several cleanup actions and are participating in ongoing investigations and remedial actions. Costs associated with these actions are not expected to be material and are expected to be found prudent and included in rates.
•The Nuclear Waste Policy Act of 1982, under which the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 14 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 11 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.
•The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.
•The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding the relicensing of PacifiCorp's Klamath River hydroelectric system.
The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.
Item 1A. Risk Factors
Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.
Corporate and Financial Structure Risks
BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.
BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:
•their respective earnings, capital requirements, and required debt and preferred stock payments;
•the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and
•regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.
BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.
A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2021, BHE had the following outstanding obligations:
•senior unsecured debt of $13.0 billion;
•junior subordinated debentures of $100 million;
•guarantees and letters of credit in respect of subsidiaries, equity method investments and other related parties aggregating $1.4 billion; and
•commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $356 million.
BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $38.7 billion as of December 31, 2021. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.
Given BHE's substantial leverage, it may not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
The terms of BHE's and its subsidiaries' debt do not limit BHE's ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's or its subsidiaries' financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain
distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.
Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.
A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market could be significantly limited, resulting in higher interest costs.
Similarly, any downgrade or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity.
Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts could be material and could adversely affect such Registrant's liquidity and cash flows.
BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp'spreferred stockholders.
Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.
BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power and Sierra Pacific and the membership interest in Eastern Energy Gas. BHE is also the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.
Business Risks
Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.
Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.
An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize the anticipated benefits of the acquisition.
BHE cannot assure that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.
The Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems, which could adversely affect each respective Registrant's financial results.
The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on United States federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third-party excavation errors; unexpected degradation of pipeline systems; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, pandemics and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. The extent of that liability would be determined by the applicable state law where any such damage occurred. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources.
Further, the Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs or other damages. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured. Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's financial results.
The Registrants are subject to increasing risk from catastrophic wildfires and may be unable to obtain enough insurance coverage at a reasonable cost or at all to adequately protect the Registrants from liability, which could materially affect the Registrants financial results and liquidity.
The risk of catastrophic and severe wildfires has increased in the western United States giving rise to large damage claims against utilities for fire-related losses. Catastrophic and severe wildfires can occur in PacifiCorp, Nevada Power and Sierra Pacific's ("Western Domestic Utilities") service territory even when the Western Domestic Utilities effectively implement their wildfire mitigation plans and prudently manage their systems.
In California, for example, where PacifiCorp operates, "inverse condemnation" currently exposes utilities to potential liability for property damages where the utility's electrical equipment was a substantial cause of the wildfire. California courts have held that utilities can be held liable under inverse condemnation without being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover attorney's fees. As a result of inverse condemnation being applied to utilities and wildfire damages, recent losses recorded by insurance companies, and the risk of an increase in the frequency, duration and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in amounts necessary to cover potential losses. Uninsured losses and increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and may not be recoverable in customer rates.
The Western Domestic Utilities monitor weather conditions with specific thresholds for designated high fire consequence areas to help ensure the safe and reliable operation of their systems during periods of elevated wildfire ignition risk. Should weather conditions become extreme, the Western Domestic Utilities may de-energize certain sections of their distribution and transmission facilities as a last resort to minimize risk to the public. These "public safety power shutoffs" could be subject to increased scrutiny by regulators and policy makers. And, although "public safety power shutoffs" are intended to minimize risk of wildfire ignition, de-energization may cause other damages for which the Western Domestic Utilities could be held liable.
Damage claims against PacifiCorp for the 2020 Wildfires (as defined below) may materially affect PacifiCorp's financial condition and results of operations.
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California. Investigations into the cause and origin of each wildfire are complex and ongoing. Several lawsuits and complaints have been filed in Oregon and California associated with the wildfires, and it is possible that additional lawsuits and complaints against PacifiCorp may be filed. If PacifiCorp is found liable for damages related to the 2020 Wildfires and is unable to, or believes that it will be unable to, recover those damages through insurance or customer rates, or access the bank and capital markets on reasonable terms, PacifiCorp's financial results could be adversely affected. Refer to Item 3. Legal Proceedings, BHE's Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the 2020 Wildfires.
Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks.
Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services or otherwise reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local legislation related to such epidemics, pandemics or other outbreaks (or other similar laws, regulations, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related assessment of late fees, due to non-payment or other circumstances. Additionally, HomeServices' real estate businesses could experience a decline (which could be significant) in real estate transactions if potential customers elect to defer purchases in reaction to any epidemic, pandemic or other outbreak or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.
Further, epidemics, pandemics or other outbreaks could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of the Registrants' renewable generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.
Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.
Each Registrant is subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability, data privacy and other laws and regulations that affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including initiatives regarding deregulation and restructuring of the utility industry, are continually being proposed and enacted that impose new or revised requirements or standards on each Registrant.
Each Registrant is required to comply with numerous federal, state, local and foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring, disposing or retiring of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; managing and reporting transactions between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the United States, and foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.
Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's financial results.
Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenues within each Registrant's service territories; new environmental requirements, including the implementation of or changes to the Affordable Clean Energy rule, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.
New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:
•Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
•Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
•Additional costs may be incurred to purchase and deploy new generating technologies;
•Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
•Operating costs may be higher and generating unit outputs may be lower;
•Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and
•The relevant Registrant's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions, nor can each Registrant determine their impact on it at this time; however, any one of these could adversely affect each Registrant's financial results through higher capital expenditures and operating costs, early closure of generating facilities or lower tax benefits or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's financial results.
Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's financial results.
State Regulatory Rate Review Proceedings
The Utilities establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases or requesting rate decreases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.
States set retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are prudently incurred in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return or recover all of its costs even if it believes such costs to be prudently incurred.
Some state regulatory commissions have authorized recovery of certain costs above the level assumed in establishing base rates through adjustment mechanisms, which may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and adjustment mechanisms or through future general regulatory rate reviews. Any of these consequences could adversely affect each Registrant's financial results.
FERC Jurisdiction
The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity in the wholesale market, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.
The NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.
The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.
Rates for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's ratemaking principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline system's regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline system and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition, the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.
Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.
GEMA Jurisdiction
The Northern Powergrid Distribution Companies, as DNOs and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year-to-year but is a control on revenue that operates independent of a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license, it can appeal the matter to the United Kingdom's CMA. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.
AUC Jurisdiction
The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.
The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing. The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulations and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.
Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its financial results.
Each Registrant relies on technology in virtually all aspects of its business. Like those of many large businesses, certain of the Registrant's technology systems have been subject to computer viruses, malicious codes, unauthorized access, phishing efforts, denial-of-service attacks and other cyber attacks and each Registrant expects to be subject to similar attacks in the future as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by physical or cyber attack could result in-service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.
Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion at one or more of each Registrant's operations could adversely affect the impacted Registrant's financial results. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire, develop, implement, adopt or protect rights around new technology, it may suffer a competitive disadvantage.
Each Registrant is actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.
Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, and continued maintenance and upgrades of existing assets.
Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, and the imposition of tariffs thereon when sourced by foreign providers, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's financial results.
Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results. Factors that could lead to a decrease in market demand include, among others:
•a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;
•an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;
•shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including shale gas sources;
•efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and private generation measures and programs;
•laws mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;
•a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;
•a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and
•sustained mild weather that reduces heating or cooling needs.
Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.
In most parts of the United States and other markets in which each Registrant operates, demand for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, including the western portion of PacifiCorp's service territory, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered generating capacity, and BHE's unregulated subsidiaries are adding solar-powered and wind-powered generating capacity, each of which is also a climate-dependent resource.
As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its financial results. The extent of fluctuation in each Registrant's financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy and Nevada Power, and terms of its wholesale sale contracts.
Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its financial results.
In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have ECAMs, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors.
Potential terrorist activities and the impact of military or other actions, could adversely affect each Registrant's financial results.
The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the United States government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.
Certain Registrants are subject to the unique risks associated with nuclear generation.
The ownership and operation of nuclear generating facilities, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, compliance with and changes in regulation of nuclear generating facilities, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Constellation Energy, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the generating facility is significantly less than market wholesale prices. The following are among the more significant of these risks:
•Operational Risk - Operations at any nuclear generating facility could degrade to the point where the generating facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the generating facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the generating facility, the generating facility could be shut down. Furthermore, a shut-down or failure at any other nuclear generating facility could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expense of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear generating facilities, including Quad Cities Station, in the future.
•Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
•Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere, such as at the Fukushima Daiichi nuclear generating facility in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.
Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its financial results.
If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenues are generated under transportation, storage and LNG contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.
Each Registrant is subject to counterparty risk, which could adversely affect its financial results.
Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant continues to monitor the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if any Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on each Registrant's liquidity and its financial results.
Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.
Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its financial results.
The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with E.ON and British Gas Trading Limited accounting for approximately 23% and 12%, respectively, of distribution revenue in 2021. AltaLink's primary source of operating revenue is the AESO. Generally, a single customer purchases the energy from BHE's independent power projects in the United States pursuant to long-term power purchase agreements. For example, certain of BHE Renewables' solar and wind independent power projects sell all of their electrical production to either PG&E or SCE, respectively. Any material payment or other performance failure by the counterparties in these arrangements could have a significant adverse impact on BHE's consolidated financial results.
BHE owns investments in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.
BHE's business operations and investments outside the United States increase its risk related to fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, United States dollars or a currency freely convertible into United States dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.
In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, pandemics (including potentially in relation to COVID-19), expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.
Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows, liquidity and financial results.
Costs of providing each Registrant's defined benefit pension and other postretirement benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Furthermore, the timing of recognition of unrecognized gains and losses associated with the Registrants' defined benefit pension plans is subject to volatility due to events that may give rise to settlement accounting. Settlement events resulting from lump sum distributions offered by certain of the Registrants' defined benefit pension plans are influenced by the interest rates used to discount a participant's lump sum distribution. When the applicable interest rates are low, lump sum distributions in a given year tend to increase resulting in a higher likelihood of triggering settlement accounting.
If the Registrant's pension and other postretirement benefit plans are in underfunded positions, the respective Registrant may be required to make cash contributions to fund such underfunded plans in the future. Additionally, each Registrant's plans have investments in domestic and foreign equity and debt securities and other investments that are subject to loss. Losses from investments could add to the volatility, size and timing of future contributions.
Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation.
In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear generating facility, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. The funds that MidAmerican Energy has invested in a nuclear decommissioning trust and a subsidiary of PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp's subsidiary to make additional cash contributions. As contributions to the trust are being made over the operating life of the respective facility, reductions in the expected operating life of the facility could also require MidAmerican Energy and PacifiCorp's subsidiary to make additional contributions to the related trust. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash.
Inflation and changes in commodity prices and fuel transportation costs may adversely affect each Registrant's financial results.
Inflation and increases in commodity prices and fuel transportation costs may affect each Registrant by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures, each Registrant may not be able to pass the costs of inflation on to its customers. If each Registrant is unable to manage cost increases or pass them on to its customers, its financial results could be adversely affected.
Cyclical fluctuations and competition in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
•rising interest rates or unemployment rates, including a sustained high unemployment rate in the United States;
•periods of economic slowdown or recession in the markets served or the adverse effects on market actions as a result of epidemics, pandemics or other outbreaks;
•decreasing home affordability;
•lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;
•inadequate home inventory levels;
•sources of new competition; and
•changes in applicable tax law.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the United States, Great Britain, Canada and global credit markets, such as those that occurred in 2008, 2009 and 2020, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the United States or globally may adversely affect the United States' credit markets and could negatively impact each Registrant's ability to access funds on favorable terms or at all. If a Registrant is unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its financial results.
Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its financial results.
Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established liabilities or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct its business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on such Registrant's financial results.
Item 1B.Unresolved Staff Comments
Not applicable.
Item 2.Properties
Each Registrant's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, LNG facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 22 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K and Notes 4 and 5 of the Notes to Consolidated Financial Statements of Eastern Energy Gas in Item 8 of this Form 10-K.
The following table summarizes Berkshire Hathaway Energy's operating electric generating facilities as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Facility Net | | Net Owned |
Energy | | | | | | Capacity | | Capacity |
Source | | Entity | | Location by Significance | | (MWs) | | (MWs) |
| | | | | | | | |
Wind | | PacifiCorp, MidAmerican Energy and BHE Renewables | | Iowa, Wyoming, Texas, Nebraska, Washington, California, Illinois, Montana, Oregon and Kansas | | 11,517 | | | 11,517 | |
Natural gas | | PacifiCorp, MidAmerican Energy, NV Energy, BHE Renewables and BHE Canada | | Nevada, Utah, Iowa, Illinois, Washington, Wyoming, Oregon, Texas, New York, Arizona and Canada | | 11,112 | | | 10,833 | |
Coal | | PacifiCorp, MidAmerican Energy and NV Energy | | Wyoming, Iowa, Utah, Nevada, Colorado and Montana | | 13,235 | | | 8,193 | |
Solar | | BHE Renewables and NV Energy | | California, Texas, Arizona, Minnesota and Nevada | | 1,719 | | | 1,571 | |
Hydroelectric | | PacifiCorp, MidAmerican Energy and BHE Renewables | | Washington, Oregon, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming | | 1,149 | | | 1,149 | |
Nuclear | | MidAmerican Energy | | Illinois | | 1,823 | | | 456 | |
Geothermal | | PacifiCorp and BHE Renewables | | California and Utah | | 377 | | | 377 | |
| | | | Total | | 40,932 | | | 34,096 | |
Additionally, as of December 31, 2021, the Company has electric generating facilities that are under construction in Nevada, Iowa and Canada having total Facility Net Capacity and Net Owned Capacity of 421 MWs.
The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through prescription, eminent domain or similar rights. PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas and Kern River in the United States; Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc in Great Britain; and AltaLink in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the United States and Canadian utilities do not have the power of eminent domain with respect to governmental, Native American or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.
With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.
Item 3.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain, South Obenchain, Two Four Two and Santiam Canyon (also known as Beachie Creek) fires, as well as to add claims for noneconomic damages. The amended complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The amended complaint seeks the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595, Multnomah County, Oregon, in which two complaints, Case No. 21cv09339 and Case No. 21cv09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek Fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages.
Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part II, Item 8 of this Form 10-K, and PacifiCorp, refer to Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Part II, Item 8 of this Form 10-K.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.
PART II
Item 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
BERKSHIRE HATHAWAY ENERGY
BHE's common stock is beneficially owned by Berkshire Hathaway, family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, and Mr. Gregory E. Abel, BHE's Chair, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
PACIFICORP
All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE. PacifiCorp declared and paid dividends to PPW Holdings LLC of $150 million in 2021 and $— million in 2020.
MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY
All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. Neither MidAmerican Funding nor MidAmerican Energy declared or paid any cash distributions or dividends to its sole member or shareholder in 2021 and 2020.
NEVADA POWER
All common stock of Nevada Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Nevada Power declared and paid dividends to NV Energy of $213 million in 2021 and $155 million in 2020.
SIERRA PACIFIC
All common stock of Sierra Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Sierra Pacific declared and paid dividends to NV Energy of $— million in 2021 and $20 million in 2020.
EASTERN ENERGY GAS
Eastern Energy Gas is a Virginia limited liability corporation whose membership interest is held solely by its parent company, BHE GT&S, which is an indirect, wholly owned subsidiary of BHE. Eastern Energy Gas did not declare or pay cash distributions to BHE GT&S in 2021 or 2020. Eastern Energy Gas declared and paid cash distributions to DEI of $4.3 billion in 2020.
Item 6.[Reserved]
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
| | | | | | | | |
Berkshire Hathaway Energy Company and its subsidiaries | | |
PacifiCorp and its subsidiaries | | |
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company | | |
Nevada Power Company and its subsidiaries | | |
Sierra Pacific Power Company and its subsidiaries | | |
Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
| | | | | | | | |
Berkshire Hathaway Energy Company and its subsidiaries | | |
PacifiCorp and its subsidiaries | | |
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company | | |
Nevada Power Company and its subsidiaries | | |
Sierra Pacific Power Company and its subsidiaries | | |
Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
Item 8.Financial Statements and Supplementary Data
| | | | | | | | |
Berkshire Hathaway Energy Company and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Comprehensive Income | | |
Consolidated Statements of Changes in Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
PacifiCorp and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Comprehensive Income | | |
Consolidated Statements of Changes in Shareholders' Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
MidAmerican Energy Company | | |
Report of Independent Registered Public Accounting Firm | | |
Balance Sheets | | |
Statements of Operations | | |
| | |
Statements of Changes in Shareholder's Equity | | |
Statements of Cash Flows | | |
Notes to Financial Statements | | |
MidAmerican Funding, LLC and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
| | |
Consolidated Statements of Changes in Member's Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Nevada Power Company and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Changes in Shareholder's Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Sierra Pacific Power Company and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Changes in Shareholder's Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Comprehensive Income | | |
Consolidated Statements of Changes in Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MES, corporate functions and intersegment eliminations.
Results of Operations
Overview
Operating revenue and earnings on common shares for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Operating revenue: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | | 5 | % |
MidAmerican Funding | 3,547 | | | 2,728 | | | 819 | | | 30 | | | 2,728 | | | 2,927 | | | (199) | | | (7) | |
NV Energy | 3,107 | | | 2,854 | | | 253 | | | 9 | | | 2,854 | | | 3,037 | | | (183) | | | (6) | |
Northern Powergrid | 1,188 | | | 1,022 | | | 166 | | | 16 | | | 1,022 | | | 1,013 | | | 9 | | | 1 | |
BHE Pipeline Group | 3,544 | | | 1,578 | | | 1,966 | | | * | | 1,578 | | | 1,131 | | | 447 | | | 40 | |
BHE Transmission | 731 | | | 659 | | | 72 | | | 11 | | | 659 | | | 707 | | | (48) | | | (7) | |
BHE Renewables | 981 | | | 936 | | | 45 | | | 5 | | | 936 | | | 932 | | | 4 | | | — | |
HomeServices | 6,215 | | | 5,396 | | | 819 | | | 15 | | | 5,396 | | | 4,473 | | | 923 | | | 21 | |
BHE and Other | 541 | | | 438 | | | 103 | | | 24 | | | 438 | | | 556 | | | (118) | | | (21) | |
Total operating revenue | $ | 25,150 | | | $ | 20,952 | | | $ | 4,198 | | | 20 | % | | $ | 20,952 | | | $ | 19,844 | | | $ | 1,108 | | | 6 | % |
| | | | | | | | | | | | | | | |
Earnings on common shares: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 889 | | | $ | 741 | | | $ | 148 | | | 20 | % | | $ | 741 | | | $ | 773 | | | $ | (32) | | | (4) | % |
MidAmerican Funding | 883 | | | 818 | | | 65 | | | 8 | | | 818 | | | 781 | | | 37 | | | 5 | |
NV Energy | 439 | | | 410 | | | 29 | | | 7 | | | 410 | | | 365 | | | 45 | | | 12 | |
Northern Powergrid | 247 | | | 201 | | | 46 | | | 23 | | | 201 | | | 256 | | | (55) | | | (21) | |
BHE Pipeline Group | 807 | | | 528 | | | 279 | | | 53 | | | 528 | | | 422 | | | 106 | | | 25 | |
BHE Transmission | 247 | | | 231 | | | 16 | | | 7 | | | 231 | | | 229 | | | 2 | | | 1 | |
BHE Renewables(1) | 451 | | | 521 | | | (70) | | | (13) | | | 521 | | | 431 | | | 90 | | | 21 | |
HomeServices | 387 | | | 375 | | | 12 | | | 3 | | 375 | | | 160 | | | 215 | | | * |
BHE and Other | 1,319 | | | 3,092 | | | (1,773) | | | (57) | | | 3,092 | | | (467) | | | 3,559 | | | * |
Total earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | (1,248) | | | (18) | % | | $ | 6,917 | | | $ | 2,950 | | | $ | 3,967 | | | * |
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful.
Earnings on common shares decreased $1,248 million for 2021 compared to 2020. Included in these results was a pre-tax unrealized gain in 2021 of $1,796 million ($1,777 million after-tax) compared to a pre-tax unrealized gain in 2020 of $4,774 million ($3,470 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares in 2021 was $3,892 million, an increase of $445 million, or 13%, compared to adjusted earnings on common shares in 2020 of $3,447 million.
The decrease in net income attributable to BHE shareholders for 2021 compared to 2020 was primarily due to:
•The Utilities' earnings increased $242 million reflecting higher electric utility margin, favorable income tax expense, from higher PTCs recognized of $139 million and the impacts of ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense. Electric retail customer volumes increased 3.8% for 2021 compared to 2020, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather;
•Northern Powergrid's earnings increased $46 million, primarily due to higher distribution performance, lower write-offs of gas exploration costs and $16 million from the weaker United States dollar, partially offset by the comparative unfavorable impact of deferred income tax charges ($109 million in second quarter 2021 and $35 million in third quarter 2020) related to enacted increases in the United Kingdom corporate income tax rate;
•BHE Pipeline Group's earnings increased $279 million, primarily due to $244 million of incremental earnings at BHE GT&S;
•BHE Renewables' earnings decreased $70 million, primarily due to lower tax equity investment earnings from the February 2021 polar vortex weather event, partially offset by earnings from tax equity investment projects reaching commercial operation and higher operating performance from owned renewable energy projects; and
•BHE and Other's earnings decreased $1,773 million, primarily due to the $1,693 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited and $95 million of higher dividends on BHE's 4.00% Perpetual Preferred Stock issued in October 2020, partially offset by favorable comparative consolidated state income tax benefits.
Earnings on common shares increased $3,967 million for 2020 compared to 2019. Included in these results was a pre-tax unrealized gain in 2020 of $4,774 million ($3,470 million after-tax) compared to a pre-tax unrealized loss in 2019 of $313 million ($227 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares in 2020 was $3,447 million, an increase of $270 million, or 9%, compared to adjusted earnings on common shares in 2019 of $3,177 million.
The increase in earnings on common shares for 2020 compared to 2019 was primarily due to:
•The Utilities' earnings increased $50 million with favorable performance at all four utilities (electric retail customer volumes increased 0.1%), including $193 million of higher PTCs recognized, offset by a comparative increase in wildfire and other storm restoration costs, primarily at PacifiCorp;
•Northern Powergrid's earnings decreased $55 million, mainly due to a deferred income tax charge in 2020 from an enacted increase in the United Kingdom corporate income tax rate;
•BHE Pipeline Group's earnings increased $106 million, primarily due to $73 million of incremental earnings at BHE GT&S and a favorable rate case settlement at Northern Natural Gas;
•BHE Renewables' earnings increased $90 million, primarily due to increased income tax benefits from renewable wind tax equity investments, largely from projects reaching commercial operation, offset by lower earnings from geothermal and natural gas facilities;
•HomeServices' earnings increased $215 million, primarily due to higher earnings from mortgage services (71% increase in funded mortgage volume) and brokerage services (13% increase in closed transaction volume) largely attributable to the favorable interest rate environment; and
•BHE and Other's earnings increased $3,559 million, primarily due to the $3,697 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited offset by higher BHE corporate interest expense and unfavorable comparative consolidated state income tax benefits.
Reportable Segment Results
PacifiCorp
Operating revenue decreased $45 million for 2021 compared to 2020, primarily due to lower retail revenue of $98 million, partially offset by higher wholesale and other revenue of $53 million. Retail revenue decreased mainly due to $234 million from the Utah and Oregon general rate case orders issued in 2020 (fully offset in expense, primarily depreciation) and price impacts of $41 million from lower rates primarily due to certain general rate case orders, partially offset by higher customer volumes of $177 million. Retail customer volumes increased 3.1%, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather. Wholesale and other revenue increased mainly due to higher wheeling revenue, average wholesale prices and REC sales, partially offset by $34 million from the Oregon RAC settlement (fully offset in depreciation expense) recognized in 2020.
Earnings increased $148 million for 2021 compared to 2020, primarily due to favorable income tax expense from higher PTCs recognized of $75 million from new wind-powered generating facilities placed in-service, and the impacts of ratemaking, lower operations and maintenance expense of $178 million and higher utility margin of $145 million, partially offset by higher depreciation and amortization expense of $255 million and lower allowances for equity and borrowed funds used during construction of $72 million. Operations and maintenance expense decreased primarily due to lower costs associated with wildfires and the Klamath Hydroelectric Settlement Agreement and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. Utility margin increased primarily due to the higher retail customer volumes, higher wheeling and wholesale revenue and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power and thermal generation costs, the price impacts from lower retail rates and higher wheeling expenses. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.
Operating revenue increased $273 million for 2020 compared to 2019, primarily due to higher retail revenue of $250 million and higher wholesale and other revenue of $23 million. Retail revenue increased primarily due to $234 million from the amortization of certain existing regulatory balances to offset the accelerated depreciation of certain property, plant and equipment and the accelerated amortization of certain regulatory asset balances in relation to Utah and Oregon general rate case orders issued in December 2020. The increase in retail revenue was also due to price impacts of $49 million from changes in sales mix, partially offset by lower customer volumes of $34 million. The increase in wholesale and other revenue was mainly due to $34 million from the amortization of certain existing regulatory balances in Oregon to offset the accelerated depreciation of certain retired wind equipment, partially offset by lower wholesale volumes. Retail customer volumes decreased 1.4% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of residential and commercial customers and the favorable impact of weather.
Earnings decreased $32 million for 2020 compared to 2019, primarily due to an increase in operations and maintenance expense due to higher costs associated with wildfires and the Klamath Hydroelectric Settlement Agreement of $169 million, higher interest expense of $25 million from higher long-term debt balances, higher pension and other postretirement costs of $13 million, lower interest income from lower average interest rates and higher property taxes of $10 million, partially offset by lower tax expense from higher PTCs recognized of $62 million from repowered and new wind-powered generating facilities, higher utility margin of $47 million and higher allowances for equity and borrowed funds used during construction of $38 million. Utility margin increased primarily due to lower coal-fueled and natural gas-fueled generation costs, lower purchased power costs and price impacts from changes in sales mix, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms and lower retail customer volumes.
MidAmerican Funding
Operating revenue increased $819 million for 2021 compared to 2020, primarily due to higher natural gas operating revenue of $430 million and higher electric operating revenue of $390 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $440 million (fully offset in cost of sales), largely due to the February 2021 polar vortex weather event. Electric operating revenue increased due to higher retail revenue of $198 million and higher wholesale and other revenue of $192 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $116 million (fully offset in expense, primarily cost of sales), higher customer volumes of $63 million and price impacts of $19 million from changes in sales mix. Electric retail customer volumes increased 5.8% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased primarily due to higher average wholesale prices of $116 million and higher wholesale volumes of $71 million.
Earnings increased $65 million for 2021 compared to 2020, primarily due to higher electric utility margin of $190 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $198 million, higher operations and maintenance expense of $20 million and lower allowances for equity and borrowed funds of $8 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. The favorable income tax benefit was largely due to higher PTCs recognized of $64 million, from new wind-powered generating facilities placed in-service, partially offset by state income tax impacts. The increase in depreciation and amortization expense was primarily due to the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service and higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities.
Operating revenue decreased $199 million for 2020 compared to 2019, primarily due to lower natural gas operating revenue of $77 million, lower electric operating revenue of $70 million, lower electric and natural gas energy efficiency program revenue of $38 million (fully offset in operations and maintenance expense) and lower other revenue of $14 million, primarily from nonregulated utility construction services. Natural gas operating revenue decreased primarily due to lower volumes and a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $68 million (fully offset in cost of sales) and a 10.2% decrease in retail customer volumes, primarily due to the unfavorable impact of weather. Electric operating revenue decreased due to lower wholesale and other revenue of $88 million, partially offset by higher retail revenue of $18 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale prices of $115 million, partially offset by higher wholesale volumes of $28 million. Electric retail revenue increased primarily due to higher customer usage of $38 million, partially offset by price impacts of $18 million from changes in sales mix. Electric retail customer volumes increased 1.2% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage.
Earnings increased $37 million for 2020 compared to 2019, primarily due to higher income tax benefit of $197 million from higher PTCs recognized of $132 million and the favorable impacts of ratemaking, partially offset by higher depreciation and amortization expense of $77 million due to additional assets placed in-service (offset by $23 million of lower Iowa revenue sharing accruals), lower allowances for equity and borrowed funds used during construction of $45 million, higher interest expense of $20 million and lower electric and natural gas utility margins. PTCs recognized increased due to higher wind-powered generation driven primarily by repowering and new wind projects placed in-service. Electric utility margin decreased due to lower wholesale revenue and the price impacts from changes in sales mix, partially offset by lower generation costs from higher wind generation and higher retail customer volumes. Natural gas utility margin decreased primarily due to lower retail customer volumes primarily due to the unfavorable impact of weather.
NV Energy
Operating revenue increased $253 million for 2021 compared to 2020, primarily due to higher electric operating revenue of $252 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $229 million, a $120 million one-time bill credit in the fourth quarter of 2020 resulting from a regulatory rate review decision (fully offset in operations and maintenance and income tax expenses) and higher retail customer volumes of $10 million, partially offset by lower base tariff general rates of $71 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 3.3%, primarily due to an increase in the average number of customers, higher customer usage and the favorable impact of weather.
Earnings increased $29 million for 2021 compared to 2020, primarily due to lower operations and maintenance expense of $90 million, lower income tax expense mainly from the impacts of ratemaking, lower interest expense of $21 million, higher interest and dividend income of $16 million and lower pension expense of $10 million, partially offset by lower electric utility margin of $97 million and higher depreciation and amortization expense of $47 million. Operations and maintenance expense decreased primarily due to lower regulatory deferrals and amortizations and lower earnings sharing at the Nevada Utilities. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by higher retail customer volumes. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.
Operating revenue decreased $183 million for 2020 compared to 2019, primarily due to lower electric operating revenue. Electric operating revenue decreased primarily due to lower fully-bundled energy rates (fully offset in cost of sales) of $164 million and a $120 million one-time bill credit in the fourth quarter of 2020 resulting from a regulatory rate review decision (fully offset in operations and maintenance and income tax expenses), partially offset by higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision. Electric retail customer volumes, including distribution only service customers, increased 1.5%, primarily due to the favorable impact of weather, largely offset by the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage.
Earnings increased $45 million for 2020 compared to 2019, primarily due to higher electric utility margin of $100 million, lower pension and post-retirement costs of $9 million and lower income tax expense mainly from the favorable impacts of ratemaking, partially offset by an increase in operations and maintenance expense, mainly from higher earnings sharing accruals at the Nevada Utilities, and higher depreciation and amortization expense of $20 million, mainly from higher plant placed in-service. Electric utility margin increased primarily due to higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision.
Northern Powergrid
Operating revenue increased $166 million for 2021 compared to 2020, primarily due to higher distribution revenue of $80 million, mainly from increased tariff rates of $40 million and a 3.2% increase in units distributed totaling $26 million, and $77 million from the weaker United States dollar.
Earnings increased $46 million for 2021 compared to 2020, primarily due to the higher distribution revenue, lower write-offs of gas exploration costs of $36 million, $16 million from the weaker United States dollar, favorable pension expense of $14 million and lower interest expense of $8 million, partially offset by higher income tax expense and higher distribution-related operating and depreciation expenses of $29 million. Earnings in 2021 included a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, while earnings in 2020 included a deferred income tax charge of $35 million related to a July 2020 enacted increase in the United Kingdom corporate income tax rate from 17% to 19% effective April 1, 2020.
Operating revenue increased $9 million for 2020 compared to 2019, primarily due to higher distribution revenue of $10 million from increased tariff rates of $40 million, partially offset by a 5.4% decrease in units distributed totaling $30 million largely due to the impacts of COVID-19.
Earnings decreased $55 million for 2020 compared to 2019, primarily due to write-offs of gas exploration costs of $44 million, higher income tax expense of $37 million and higher distribution-related operating and depreciation expenses of $18 million, partially offset by higher distribution revenue, lower pension expense of $22 million, including lower pension settlement losses recognized in 2020 compared to 2019, and lower interest expense of $9 million. The increase in income tax expense is due to a change in the United Kingdom corporate income tax rate that resulted in a deferred income tax charge of $35 million.
BHE Pipeline Group
Operating revenue increased $1,966 million for 2021 compared to 2020, primarily due to $1,828 million of incremental revenue at BHE GT&S, acquired in November 2020, higher gas sales of $115 million ($38 million largely offset in costs of sales) at Northern Natural Gas and higher transportation revenue of $29 million at Kern River largely due to higher rates and volumes, partially offset by lower transportation revenue of $24 million at Northern Natural Gas primarily due to lower volumes. The variances in gas sales and transportation revenue at Northern Natural Gas included favorable impacts of $77 million and $49 million, respectively, from the February 2021 polar vortex weather event.
Earnings increased $279 million for 2021 compared to 2020, primarily due to $244 million of incremental earnings at BHE GT&S, favorable earnings of $19 million at Kern River from the higher transportation revenue and higher earnings of $15 million at Northern Natural Gas, primarily due to higher gross margin on gas sales and higher transportation revenue, each due to the favorable impacts of the February 2021 polar vortex weather event, offset by the lower transportation revenue.
Operating revenue increased $447 million for 2020 compared to 2019, primarily due to $331 million of incremental revenue at BHE GT&S, a favorable rate case settlement at Northern Natural Gas of $101 million and higher transportation revenue of $43 million, partially offset by lower gas sales at Northern Natural Gas of $23 million related to system balancing activities (largely offset in cost of sales).
Earnings increased $106 million for 2020 compared to 2019, primarily due to $73 million of incremental earnings BHE GT&S, the higher transportation revenue, and a favorable after-tax, rate case settlement at Northern Natural Gas of $32 million, partially offset by higher property and other tax expense of $17 million, including a non-recurring property tax refund in 2019, higher depreciation and amortization expense of $13 million due to increased spending on capital projects and lower interest income of $9 million.
BHE Transmission
Operating revenue increased $72 million for 2021 compared to 2020, primarily due to $47 million from the stronger United States dollar, a regulatory decision received in November 2020 at AltaLink and higher revenue from the Montana-Alberta Tie Line of $11 million.
Earnings increased $16 million for 2021 compared to 2020, primarily due to $12 million from the stronger United States dollar, higher earnings from the Montana-Alberta Tie Line and lower non-regulated interest expense at BHE Canada, partially offset by the impact of a regulatory decision received in April 2020 at AltaLink.
Operating revenue decreased $48 million for 2020 compared to 2019, primarily due to a regulatory decision received in November 2020 at AltaLink and the stronger United States dollar of $7 million.
Earnings increased $2 million for 2020 compared to 2019, primarily due to lower non-regulated interest expense at BHE Canada and higher net income at BHE U.S. Transmission of $6 million mainly due to improved equity earnings from ETT, partially offset by the impacts of regulatory decisions received in 2020 and 2019 at AltaLink.
BHE Renewables
Operating revenue increased $45 million for 2021 compared to 2020, primarily due to higher natural gas, solar, wind and hydro revenues from favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $30 million.
Earnings decreased $70 million for 2021 compared to 2020, primarily due to lower wind earnings of $83 million, largely from lower tax equity investment earnings of $90 million, and lower hydro earnings of $10 million, mainly due to lower income from a declining financial asset balance, partially offset by higher solar earnings of $22 million, mainly due to the higher operating revenue and lower depreciation expense. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $165 million, primarily due to the February 2021 polar vortex weather event, and lower commitment fee income, partially offset by $87 million of earnings from projects reaching commercial operation.
Operating revenue increased $4 million for 2020 compared to 2019, primarily due to higher natural gas, solar and hydro revenues of $21 million due to favorable generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $14 million and lower geothermal revenues of $4 million from lower pricing.
Earnings increased $90 million for 2020 compared to 2019, primarily due to favorable wind tax equity investment earnings of $129 million, partially offset by lower geothermal earnings of $22 million, due to higher operations and maintenance expense and lower pricing, and lower natural gas earnings of $17 million, due to lower margins. Wind tax equity investment earnings improved due to $147 million of earnings from projects reaching commercial operation, partially offset by lower commitment fee income and lower earnings from existing tax equity investments of $6 million.
HomeServices
Operating revenue increased $819 million for 2021 compared to 2020, primarily due to higher brokerage revenue of $951 million, partially offset by lower mortgage revenue of $169 million from an 8% decrease in funded volume due to a decrease in refinance activity. The increase in brokerage revenue was due to a 21% increase in closed transaction volume at existing companies resulting from increases in average sales price and closed units.
Earnings increased $12 million for 2021 compared to 2020, primarily due to higher earnings from brokerage and franchise services of $81 million, largely attributable to the increase in closed transaction volume at existing companies, partially offset by lower earnings from mortgage services of $68 million from the decrease in refinance activity.
Operating revenue increased $923 million for 2020 compared to 2019, primarily due to higher brokerage revenue of $440 million from a 13% increase in closed transaction volume and higher mortgage revenue of $423 million from a 71% increase in funded mortgage volume due to an increase in refinance activity.
Earnings increased $215 million for 2020 compared to 2019, primarily due to higher earnings at mortgage services of $138 million and higher earnings at brokerage services largely attributable to the favorable interest rate environment.
BHE and Other
Operating revenue increased $103 million for 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MES, from favorable pricing offset by lower volumes.
Earnings decreased $1,773 million for 2021 compared to 2020, primarily due to the $1,693 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $95 million of higher dividends on BHE's 4.00% Perpetual Preferred Stock issued in October 2020, higher corporate costs and higher BHE corporate interest expense from debt issuances in March and October 2020, partially offset by favorable comparative consolidated state income tax benefits and higher earnings of $17 million at MES.
Operating revenue decreased $118 million for 2020 compared to 2019, primarily due to lower electricity and natural gas sales revenue at MES, from lower volumes.
Earnings increased $3,559 million for 2020 compared to 2019, primarily due to the $3,697 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited, partially offset by higher BHE corporate interest expense from debt issuances in March and October 2020 and unfavorable comparative consolidated state income tax benefits.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of December 31, 2021, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | BHE | | |
| | | | | | | | | | | | | Pipeline Group, | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | HomeServices | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | and Other | | Total |
| | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 18 | | | $ | 179 | | | $ | 233 | | | $ | 42 | | | $ | 39 | | | $ | 75 | | | $ | 510 | | | $ | 1,096 | |
| | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 271 | | | 851 | | | 3,300 | | | 11,281 | |
Less: | | | | | | | | | | | | | | | |
Short-term debt | — | | | — | | | — | | | (339) | | | (1) | | | (245) | | | (1,424) | | | (2,009) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | (589) | |
Net credit facilities | 3,500 | | | 982 | | | 1,139 | | | 311 | | | 270 | | | 605 | | | 1,876 | | | 8,683 | |
| | | | | | | | | | | | | | | |
Total net liquidity | $ | 3,518 | | | $ | 1,161 | | | $ | 1,372 | | | $ | 353 | | | $ | 309 | | | $ | 680 | | | $ | 2,386 | | | $ | 9,779 | |
Credit facilities: | | | | | | | | | | | | | | | |
Maturity dates | 2024 | | 2024 | | 2022, 2024 | | 2024 | | 2024 | | 2022, 2026 | | 2022, 2026 | | |
| | | | | | | | | | | | | | | |
(1) Includes drawn uncommitted credit facilities totaling $1 million at Northern Powergrid.
Refer to Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $8.7 billion and $6.2 billion, respectively. The increase was primarily due to $970 million of incremental net cash flows from operating activities at BHE GT&S, improved operating results and changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $6,224 million and $6,206 million, respectively. The increase was primarily due to an increase in income tax receipts and improved operating results, partially offset by changes in working capital.
The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(5.8) billion and $(13.2) billion, respectively. The change was primarily due to lower funding of tax equity investments, lower cash paid for acquisitions and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $(13.2) billion and $(9.0) billion, respectively. The change was primarily due to higher cash paid for acquisitions and higher funding of tax equity investments, partially offset by lower capital expenditures of $599 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Natural Gas Transmission and Storage Business Acquisition
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Questar, exclusive of the Questar Pipeline Group (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments.
On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion to Dominion Questar on November 2, 2020.
On July 9, 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. On July 14, 2021, BHE received the Purchase Price Repayment Amount of approximately $1.3 billion in cash.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2021 were $(3.1) billion. Sources of cash totaled $2.4 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $5.5 billion and consisted mainly of preferred stock redemptions totaling $2.1 billion, repayments of subsidiary debt totaling $2.0 billion, distributions to noncontrolling interests of $488 million, repayments of BHE senior debt totaling $450 million and net repayments of short-term debt totaling $276 million.
Net cash flows from financing activities for the year ended December 31, 2020 were $7.1 billion. Sources of cash totaled $11.7 billion and consisted of proceeds from BHE senior debt issuances of $5.2 billion, proceeds from preferred stock issuances of $3.8 billion and proceeds from subsidiary debt issuances totaling $2.7 billion. Uses of cash totaled $4.5 billion and consisted mainly of $2.8 billion for repayments of subsidiary debt, net repayments of short-term debt of $939 million and $350 million for repayments of BHE senior debt.
Net cash flows from financing activities for the year ended December 31, 2019 were $3.1 billion. Sources of cash totaled $5.4 billion and consisted of proceeds from subsidiary debt issuances totaling $4.7 billion and net proceeds from short-term debt of $684 million. Uses of cash totaled $2.3 billion and consisted mainly of $1.9 billion for repayments of subsidiary debt and repurchases of common stock of $293 million.
Debt Repurchases
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Preferred Stock Issuance
On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration.
Preferred Stock Redemptions
For the year ended December 31, 2021, BHE redeemed at par 2,100,012 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $2.1 billion.
Common Stock Transactions
For the years ended December 31, 2020 and 2019, BHE repurchased 180,358 shares of its common stock for $126 million and 447,712 shares of its common stock for $293 million, respectively.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are as follows (in millions):
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| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
PacifiCorp | $ | 2,175 | | | $ | 2,540 | | | $ | 1,513 | | | $ | 2,001 | | | $ | 3,317 | | | $ | 2,501 | |
MidAmerican Funding | 2,810 | | | 1,836 | | | 1,912 | | | 1,913 | | | 2,650 | | | 2,311 | |
NV Energy | 657 | | | 675 | | | 749 | | | 1,480 | | | 1,839 | | | 2,087 | |
Northern Powergrid | 602 | | | 682 | | | 742 | | | 677 | | | 633 | | | 632 | |
BHE Pipeline Group | 687 | | | 659 | | | 1,128 | | | 1,064 | | | 987 | | | 981 | |
BHE Transmission | 247 | | | 372 | | | 279 | | | 220 | | | 226 | | | 309 | |
BHE Renewables | 122 | | | 95 | | | 225 | | | 109 | | | 371 | | | 198 | |
HomeServices | 54 | | | 36 | | | 42 | | | 62 | | | 41 | | | 40 | |
BHE and Other(1) | 10 | | | (130) | | | 21 | | | 24 | | | 3 | | | 4 | |
Total | $ | 7,364 | | | $ | 6,765 | | | $ | 6,611 | | | $ | 7,550 | | | $ | 10,067 | | | $ | 9,063 | |
(1)BHE and Other includes intersegment eliminations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Wind generation | $ | 2,828 | | | $ | 2,125 | | | $ | 1,339 | | | $ | 1,010 | | | $ | 2,590 | | | $ | 2,283 | |
Electric distribution | 1,537 | | | 1,719 | | | 1,694 | | | 1,696 | | | 1,723 | | | 1,556 | |
Electric transmission | 1,070 | | | 958 | | | 813 | | | 1,624 | | | 2,380 | | | 1,985 | |
Natural gas transmission and storage | 717 | | 640 | | 1,068 | | | 908 | | | 882 | | | 879 | |
Solar generation | 5 | | 16 | | 157 | | | 189 | | | 760 | | | 949 | |
Other | 1,207 | | | 1,307 | | | 1,540 | | | 2,123 | | | 1,732 | | | 1,411 | |
Total | $ | 7,364 | | | $ | 6,765 | | | $ | 6,611 | | | $ | 7,550 | | | $ | 10,067 | | | $ | 9,063 | |
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $540 million for 2021, $848 million for 2020 and $1,486 million for 2019. MidAmerican Energy placed in-service 294 MWs during 2021, 729 MWs during 2020, including the acquisition of an existing 80-MW wind farm and 1,019 MWs during 2019. All of these wind-powered generating facilities placed in-service in 2021, 2020 and 2019 qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa EAC until these generation assets are reflected in base rates. Planned spending for the construction of wind-powered generating facilities totals $190 million in 2022, $1,744 million in 2023 and $1,678 million in 2024.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $354 million for 2021, $37 million for 2020 and $369 million for 2019. Planned spending for repowering totals $509 million in 2022. MidAmerican Energy expects its repowered facilities to meet IRS guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 865 MWs of current repowering projects not in-service as of December 31, 2021, 564 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $107 million for 2021, $1,148 million for 2020 and $338 million for 2019. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $131 million in 2022, $405 million in 2023 and $373 million in 2024. The energy production from the new wind-powered generating facilities placed in-service by the end of 2024 is expected to qualify for 60% of the federal PTCs available for 10 years once the equipment is placed in-service.
◦Repowering of existing wind-powered generating facilities at PacifiCorp totaling $9 million for 2021, $125 million for 2020 and $585 million for 2019. All existing wind-powered generating facilities at PacifiCorp have been repowered as of December 31, 2021.
◦The 2021 IRP also included PacifiCorp's planned acquisition and repowering of two wind-powered generating facilities. The repowered facilities are expected to be placed in-service in 2023 and 2024. PacifiCorp spent $11 million in 2021 and planned spending for acquiring and repowering generating facilities totals $60 million in 2022, $36 million in 2023 and $34 million in 2024.
◦Construction of wind-powered generating facilities at BHE Renewables totaling $155 million for 2021 and $15 million for 2019. In May 2021, BHE Renewables completed the asset acquisition of a 54-MW wind-powered generating facility located in Iowa. In December 2021, BHE Renewables completed asset acquisitions of 158-MW and 200-MW wind-powered generating facilities located in Texas. Planned spending for future wind generation totals $306 million in 2023 and $102 million in 2024.
•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦PacifiCorp's transmission investment in 2021 through 2024 primarily reflecting planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. PacifiCorp is advancing permitting and regulatory approvals related to the projects. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $565 million in 2022, $1,143 million in 2023 and $437 million in 2024.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Planned spending for the expansion programs estimated to be placed in-service in 2026-2028 totals $61 million in 2022, $148 million in 2023 and $498 million in 2024.
◦Operating expenditures include spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for asset modernization, pipeline integrity projects and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, with total spend of $132 million in 2021 and planned spending of $93 million in 2022 and $58 million in 2023.
◦Construction of solar-powered generating facilities at the Nevada Utilities' includes expenditures for three solar photovoltaic facilities, including a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada, with commercial operation expected by the end of 2023; a 250 MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada, with commercial operation expected by the end of 2023; and a 350 MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada, with commercial operation expected by the end of 2024. The facilities located in Humboldt County will be jointly owned and operated by Nevada Power and Sierra Pacific. Planned spending totals $702 million in 2023 and $799 million in 2024.
◦Construction of solar-powered generating facilities at BHE Renewables' includes expenditures for a 48-MW solar photovoltaic facility with an additional 52 MWs of capacity of co-located battery storage in Kern County, California, with commercial operation expected by November 30, 2024. Planned spending totals $150 million in 2024.
•Other capital expenditures includes both growth and operating expenditures, including spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of CCR.
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits.
As of December 31, 2021, the Company's investments that are accounted for under the equity method had short- and long-term debt of $2.7 billion, unused revolving credit facilities of $200 million and letters of credit outstanding of $88 million. As of December 31, 2021, the Company's pro-rata share of such short- and long-term debt was $1.3 billion, unused revolving credit facilities was $100 million and outstanding letters of credit was $43 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.
Material Cash Requirements
The Company has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Note 9, 10 and 11), operating and financing leases (refer to Note 6), firm commitments (refer to Note 16), letters of credit (refer to Note 9), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 12) and AROs (refer to Note 14). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The Company has cash requirements relating to interest payments of $32.4 billion on long-term debt, including $2.1 billion due in 2022.
Additionally, the Company has invested in wind projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $— million, $2,736 million and $1,619 million in 2021, 2020 and 2019, respectively, and has commitments as of December 31, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $356 million in 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
Regulatory Matters
The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding the Company's general regulatory framework and current regulatory matters.
Quad Cities NuclearGenerating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1, 2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of BHE and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
BHE and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, the applicable entities' credit ratings from the recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, the Company would have been required to post $460 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the United States and Canada, the Regulated Businesses operate under cost-of-service based rate structures administered by various state and provincial commissions and the FERC. Under these rate structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
The Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $4.0 billion and total regulatory liabilities were $7.2 billion as of December 31, 2021. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Regulated Businesses' regulatory assets and liabilities.
Impairment of Goodwill and Long-Lived Assets
The Company's Consolidated Balance Sheet as of December 31, 2021 includes goodwill of acquired businesses of $11.7 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2021. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings or rate base; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors.
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.
Pension and Other Postretirement Benefits
Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2021, the Company recognized a net asset totaling $433 million for the funded status of the defined benefit pension and other postretirement benefit plans. As of December 31, 2021, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled $297 million and in AOCI totaled $428 million.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2021.
The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2025, at which point the rate of increase is assumed to remain constant.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Domestic Plans | | |
| | | | | Other Postretirement | | United Kingdom |
| Pension Plans | | Benefit Plans | | Pension Plan |
| +0.5% | | -0.5% | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | | | | | |
Effect on December 31, 2021 | | | | | | | | | | | |
Benefit Obligations: | | | | | | | | | | | |
Discount rate | $ | (136) | | | $ | 153 | | | $ | (33) | | | $ | 37 | | | $ | (162) | | | $ | 189 | |
| | | | | | | | | | | |
Effect on 2021 Periodic Cost: | | | | | | | | | | | |
Discount rate | $ | — | | | $ | 5 | | | $ | 1 | | | $ | — | | | $ | (20) | | | $ | 23 | |
Expected rate of return on plan assets | (13) | | | 13 | | | (4) | | | 4 | | | (12) | | | 12 | |
A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and the Company's funding policy for each plan.
Income Taxes
In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.
It is probable the Company's regulated businesses will continue to pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $2.8 billion and will be included in regulated rates when the temporary differences reverse.
The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely; however, the Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of the Company's undistributed foreign earnings were repatriated, the dividends may be subject to taxation in the United States but the tax is not expected to be material.
Revenue Recognition - Unbilled Revenue
Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. The determination of customer invoices is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the Great Britain distribution businesses, when information is received from the national settlement system. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $718 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's business platforms has established guidelines for credit risk management.
Commodity Price Risk
The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage and transmission and transportation constraints. The Company does not engage in a material amount of proprietary trading activities. To manage a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $26 million and $35 million, respectively, as of December 31, 2021 and 2020, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Not designated as hedging contracts | $ | 20 | | | $ | 116 | | | $ | (76) | |
Designated as hedging contracts | (10) | | | (5) | | | (15) | |
Total commodity derivative contracts | $ | 10 | | | $ | 111 | | | $ | (91) | |
| | | | | |
As of December 31, 2020: | | | | | |
Not designated as hedging contracts | $ | 103 | | | $ | 143 | | | $ | 63 | |
Designated as hedging contracts | (4) | | | 10 | | | (18) | |
Total commodity derivative contracts | $ | 99 | | | $ | 153 | | | $ | 45 | |
The settled cost of certain of the Company's commodity derivative contracts not designated as hedging contracts is included in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, wholesale natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms. As of December 31, 2021 and 2020, a net regulatory asset of $71 million and a net regulatory liability of $16 million, respectively, was recorded related to the net derivative asset of $20 million and $103 million, respectively. The difference between the net regulatory asset and the net derivative asset relates primarily to a power purchase agreement derivative at BHE Renewables. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts, to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility.
Interest Rate Risk
The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt, future debt issuances and mortgage commitments. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 9, 10, 11, and 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of the Company's short and long-term debt.
As of December 31, 2021 and 2020, the Company had short- and long-term variable-rate obligations totaling $3.7 billion and $4.4 billion, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. Changes in fair value of agreements designated as cash flow hedges are reported in AOCI to the extent the hedge is effective until the forecasted transaction occurs. Changes in fair value of agreements not designated as hedging contracts are recognized in earnings. As of December 31, 2021 and 2020, the Company had variable-to-fixed interest rate swaps with notional amounts of $533 million and $1,083 million, respectively, and £174 million and £121 million, respectively, to protect the Company against an increase in interest rates. Additionally, as of December 31, 2021 and 2020, the Company had mortgage commitments, net, with notional amounts of $1,512 million and $1,636 million, respectively, to protect the Company against an increase in interest rates. The fair value of the Company's interest rate derivative contracts was a net derivative asset of $16 million as of December 31, 2021 and a net derivative liability of $3 million as of December 31, 2020. A hypothetical 10 basis point increase and a 10 basis point decrease in interest rates would not have a material impact on the Company.
The Company holds foreign currency swaps with the purpose of hedging the foreign currency exchange rate associated with Euro denominated debt. As of December 31, 2021, the Company had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of the Company's foreign currency swaps as of December 31.
Equity Price Risk
Market prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.
As of December 31, 2021 and 2020, the Company's investment in BYD Company Limited common stock represented approximately 92% and 91%, respectively, of the total fair value of the Company's equity securities. The majority of the Company's remaining equity securities are held in a trust related to the decommissioning of nuclear generation assets and the realized and unrealized gains and losses are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. The following table summarizes the Company's investment in BYD Company Limited as of December 31, 2021 and 2020 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated | | Hypothetical |
| | | Hypothetical | | Fair Value after | | Percentage Increase |
| Fair | | Price | | Hypothetical | | (Decrease) in BHE |
| Value | | Change | | Change in Prices | | Shareholders' Equity |
| | | | | | | |
As of December 31, 2021 | $ | 7,693 | | | 30% increase | | $ | 10,001 | | | 3 | % |
| | | 30% decrease | | 5,385 | | | (3) | |
| | | | | | | |
As of December 31, 2020 | $ | 5,897 | | | 30% increase | | $ | 7,666 | | | 2 | % |
| | | 30% decrease | | 4,128 | | | (2) | |
Foreign Currency Exchange Rate Risk
BHE's business operations and investments outside of the United States increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound and the Canadian dollar. BHE's reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from BHE's foreign operations changes with the fluctuations of the currency in which they transact.
Northern Powergrid's functional currency is the British pound. As of December 31, 2021, a 10% devaluation in the British pound to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $506 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid of $25 million in 2021.
BHE Canada's functional currency is the Canadian dollar. As of December 31, 2021, a 10% devaluation in the Canadian dollar to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $384 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for BHE Canada of $19 million in 2021.
Credit Risk
Domestic Regulated Operations
The Utilities are exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.
Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2021, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
As of December 31, 2021, NV Energy's aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.
BHE GT&S primary customers include electric and natural gas distribution utilities and LNG export, import and storage customers. Northern Natural Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of BHE GT&S, Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until they meet the creditworthiness requirements of the respective tariff.
Northern Powergrid
The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to supply companies. The supply companies purchase electricity from generators and traders, sell the electricity to end-use customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses. During 2021, E.ON and certain of its affiliates and British Gas Trading Limited represented approximately 23% and 12%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. The industry operates in accordance with a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Northern Powergrid Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.
BHE Canada
AltaLink's primary source of operating revenue is the AESO, an entity rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $719 million for the year ended December 31, 2021.
BHE Renewables
BHE Renewables owns independent power projects that generally have separate project financing agreements. These projects source of operating revenue is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2023 and 2043. Because of the dependence generally from a single customer at each project, any material failure of the customer to fulfill its obligations would significantly impair that project's ability to meet its existing and future obligations. Total operating revenue for BHE Renewables was $981 million for the year ended December 31, 2021.
Other Energy Business
MES is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with financial institutions and other market participants. Credit risk may be concentrated to the extent that MES' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MES analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MES enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MES exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, MES' aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and the Shareholders of
Berkshire Hathaway Energy Company
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2021, the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 7 to the financial statements
Critical Audit Matter Description
The Company, through its regulated businesses, is subject to rate regulation by the Federal Energy Regulatory Commission as well as certain other regulatory commissions (collectively, the "Commissions"), which have jurisdiction with respect to the rates of the Company's regulated businesses in the respective service territories where the Company operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense and income tax expense (benefit).
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow the Company an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit the Company's ability to recover their costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
California and Oregon 2020 Wildfires — Contingencies — See Note 16 to the financial statements
Critical Audit Matter Description
The Company has loss contingencies related to the California and Oregon 2020 wildfires (the "2020 wildfires"). The Company has recorded estimated liabilities, net of expected insurance recoveries, of $136 million as of December 31, 2021, which represents its best estimate of probable losses, net of expected insurance recoveries, as a result of the 2020 wildfires.
We identified wildfire-related contingencies and the related disclosure as a critical audit matter because of the significant judgments made by management to estimate the losses. This required the application of a high degree of judgment and extensive effort when performing audit procedures to evaluate the reasonableness of management's estimate of the losses and disclosure related to wildfire-related loss contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding its estimate of losses for wildfire-related contingencies and the related disclosure included the following, among others:
•We evaluated management's judgments related to whether a loss was probable and reasonably estimable, reasonably possible, or remote for each individual wildfire by inquiring of management and the Company's external and internal legal counsel regarding the amounts of probable and reasonably estimable, reasonably possible, and remote losses, including the potential impact of information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire, and external information for any evidence that might contradict management's assertions.
•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management and its external and internal legal counsel.
•We tested the significant assumptions used in determining the estimate, including, but not limited to, information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire.
•We read legal letters from the Company's external and internal legal counsel regarding information regarding ongoing litigation related to the 2020 wildfires and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
February 25, 2022
We have served as the Company's auditor since 1991.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 1,096 | | | $ | 1,290 | |
Restricted cash and cash equivalents | 127 | | | 140 | |
Trade receivables, net | 2,468 | | | 2,107 | |
Inventories | 1,122 | | | 1,168 | |
Mortgage loans held for sale | 1,263 | | | 2,001 | |
Regulatory assets | 544 | | | 283 | |
Other current assets | 1,628 | | | 2,458 | |
Total current assets | 8,248 | | | 9,447 | |
| | | |
Property, plant and equipment, net | 89,816 | | | 86,128 | |
Goodwill | 11,650 | | | 11,506 | |
Regulatory assets | 3,419 | | | 3,157 | |
Investments and restricted cash and cash equivalents and investments | 15,788 | | | 14,320 | |
Other assets | 3,144 | | | 2,758 | |
| | | |
Total assets | $ | 132,065 | | | $ | 127,316 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 2,136 | | | $ | 1,867 | |
Accrued interest | 537 | | | 555 | |
Accrued property, income and other taxes | 606 | | | 582 | |
Accrued employee expenses | 372 | | | 383 | |
| | | |
Short-term debt | 2,009 | | | 2,286 | |
Current portion of long-term debt | 1,265 | | | 1,839 | |
Other current liabilities | 1,837 | | | 1,626 | |
Total current liabilities | 8,762 | | | 9,138 | |
| | | |
BHE senior debt | 13,003 | | | 12,997 | |
BHE junior subordinated debentures | 100 | | | 100 | |
Subsidiary debt | 35,394 | | | 34,930 | |
Regulatory liabilities | 6,960 | | | 7,221 | |
Deferred income taxes | 12,938 | | | 11,775 | |
Other long-term liabilities | 4,319 | | | 4,178 | |
Total liabilities | 81,476 | | | 80,339 | |
| | | |
Commitments and contingencies (Note 16) | 0 | | 0 |
| | | |
Equity: | | | |
BHE shareholders' equity: | | | |
Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding | 1,650 | | | 3,750 | |
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 6,374 | | | 6,377 | |
Long-term income tax receivable | (744) | | | (658) | |
Retained earnings | 40,754 | | | 35,093 | |
Accumulated other comprehensive loss, net | (1,340) | | | (1,552) | |
Total BHE shareholders' equity | 46,694 | | | 43,010 | |
Noncontrolling interests | 3,895 | | | 3,967 | |
Total equity | 50,589 | | | 46,977 | |
| | | |
Total liabilities and equity | $ | 132,065 | | | $ | 127,316 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
Energy | $ | 18,935 | | | $ | 15,556 | | | $ | 15,371 | |
Real estate | 6,215 | | | 5,396 | | | 4,473 | |
Total operating revenue | 25,150 | | | 20,952 | | | 19,844 | |
| | | | | |
Operating expenses: | | | | | |
Energy: | | | | | |
Cost of sales | 5,504 | | | 4,187 | | | 4,586 | |
Operations and maintenance | 3,991 | | | 3,545 | | | 3,318 | |
Depreciation and amortization | 3,829 | | | 3,410 | | | 2,965 | |
Property and other taxes | 789 | | | 634 | | | 574 | |
Real estate | 5,710 | | | 4,885 | | | 4,251 | |
Total operating expenses | 19,823 | | | 16,661 | | | 15,694 | |
| | | | | |
Operating income | 5,327 | | | 4,291 | | | 4,150 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (2,118) | | | (2,021) | | | (1,912) | |
Capitalized interest | 64 | | | 80 | | | 77 | |
Allowance for equity funds | 126 | | | 165 | | | 173 | |
Interest and dividend income | 89 | | | 71 | | | 117 | |
Gains (losses) on marketable securities, net | 1,823 | | | 4,797 | | | (288) | |
Other, net | (17) | | | 88 | | | 97 | |
Total other income (expense) | (33) | | | 3,180 | | | (1,736) | |
| | | | | |
Income before income tax (benefit) expense and equity loss | 5,294 | | | 7,471 | | | 2,414 | |
Income tax (benefit) expense | (1,132) | | | 308 | | | (598) | |
Equity loss | (237) | | | (149) | | | (44) | |
Net income | 6,189 | | | 7,014 | | | 2,968 | |
Net income attributable to noncontrolling interests | 399 | | | 71 | | | 18 | |
Net income attributable to BHE shareholders | 5,790 | | | 6,943 | | | 2,950 | |
Preferred dividends | 121 | | | 26 | | | — | |
Earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | 2,950 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 6,189 | | | $ | 7,014 | | | $ | 2,968 | |
| | | | | |
Other comprehensive income, net of tax: | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $55, $(19) and $(15) | 174 | | | (65) | | | (59) | |
Foreign currency translation adjustment | (24) | | | 234 | | | 327 | |
| | | | | |
Unrealized gains (losses) on cash flow hedges, net of tax of $10, $(3) and $(8) | 67 | | | (15) | | | (29) | |
Total other comprehensive income, net of tax | 217 | | | 154 | | | 239 | |
| | | | | |
Comprehensive income | 6,406 | | | 7,168 | | | 3,207 | |
Comprehensive income attributable to noncontrolling interests | 404 | | | 71 | | | 18 | |
Comprehensive income attributable to BHE shareholders | $ | 6,002 | | | $ | 7,097 | | | $ | 3,189 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| BHE Shareholders' Equity | | | | |
| | | | | | | Long-term | | | | Accumulated | | | | |
| | | | | Additional | | Income | | | | Other | | | | |
| Preferred | | Common | | Paid-in | | Tax | | Retained | | Comprehensive | | Noncontrolling | | Total |
| Stock | | Stock | | Capital | | Receivable | | Earnings | | Loss, Net | | Interests | | Equity |
| | | | | | | | | | | | | | | |
Balance, December 31, 2018 | $ | — | | | $ | — | | | $ | 6,371 | | | $ | (457) | | | $ | 25,624 | | | $ | (1,945) | | | $ | 130 | | | $ | 29,723 | |
Net income | — | | | — | | | — | | | — | | | 2,950 | | | — | | | 18 | | | 2,968 | |
Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 239 | | | — | | | 239 | |
Long-term income tax receivable adjustments | — | | | — | | | 33 | | | (73) | | | — | | | — | | | — | | | (40) | |
Common stock purchases | — | | | — | | | (15) | | | — | | | (278) | | | — | | | — | | | (293) | |
Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (22) | | | (22) | |
Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | 3 | | | 3 | |
Balance, December 31, 2019 | — | | | — | | | 6,389 | | | (530) | | | 28,296 | | | (1,706) | | | 129 | | | 32,578 | |
Net income | — | | | — | | | — | | | — | | | 6,943 | | | — | | | 70 | | | 7,013 | |
Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 154 | | | — | | | 154 | |
Long-term income tax receivable adjustments | — | | | — | | | — | | | (128) | | | — | | | — | | | — | | | (128) | |
Issuance of preferred stock | 3,750 | | | — | | | — | | | — | | | — | | | — | | | — | | | 3,750 | |
Preferred stock dividend | — | | | — | | | — | | | — | | | (26) | | | — | | | — | | | (26) | |
Common stock purchases | | | — | | | (6) | | | — | | | (120) | | | — | | | — | | | (126) | |
Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (121) | | | (121) | |
Purchase of noncontrolling interest | — | | | — | | | (5) | | | — | | | — | | | — | | | (28) | | | (33) | |
BHE GT&S acquisition - noncontrolling interest | — | | | — | | | — | | | — | | | — | | | — | | | 3,916 | | | 3,916 | |
Other equity transactions | — | | | — | | | (1) | | | — | | | — | | | — | | | 1 | | | — | |
Balance, December 31, 2020 | 3,750 | | | — | | | 6,377 | | | (658) | | | 35,093 | | | (1,552) | | | 3,967 | | | 46,977 | |
Net income | — | | | — | | | — | | | — | | | 5,790 | | | — | | | 397 | | | 6,187 | |
Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 212 | | | 5 | | | 217 | |
Long-term income tax receivable adjustments | — | | | — | | | — | | | (86) | | | (8) | | | — | | | — | | | (94) | |
Preferred stock redemptions | (2,100) | | | — | | | — | | | — | | | — | | | — | | | — | | | (2,100) | |
Preferred stock dividend | — | | | — | | | — | | | — | | | (121) | | | — | | | — | | | (121) | |
| | | | | | | | | | | | | | | |
Distributions | | | — | | | — | | | — | | | — | | | — | | | (478) | | | (478) | |
Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | |
Purchase of noncontrolling interest | — | | | — | | | (3) | | | — | | | — | | | — | | | (4) | | | (7) | |
Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | (1) | | | (1) | |
Balance, December 31, 2021 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,754 | | | $ | (1,340) | | | $ | 3,895 | | | $ | 50,589 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions) | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 6,189 | | | $ | 7,014 | | | $ | 2,968 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
(Gains) losses on marketable securities, net | (1,823) | | | (4,797) | | | 288 | |
Losses on other items, net | 112 | | | 54 | | | 43 | |
Depreciation and amortization | 3,881 | | | 3,455 | | | 3,011 | |
Allowance for equity funds | (126) | | | (165) | | | (173) | |
Equity loss, net of distributions | 380 | | | 248 | | | 93 | |
Changes in regulatory assets and liabilities | (668) | | | (415) | | | 153 | |
Deferred income taxes and investment tax credits, net | 646 | | | 1,880 | | | 290 | |
Other, net | (169) | | | (77) | | | 23 | |
Changes in other operating assets and liabilities, net of effects from acquisitions: | | | | | |
Trade receivables and other assets | 553 | | | (1,318) | | | (372) | |
Derivative collateral, net | 82 | | | 43 | | | (25) | |
Pension and other postretirement benefit plans | (39) | | | (65) | | | (51) | |
Accrued property, income and other taxes, net | (489) | | | (134) | | | (16) | |
Accounts payable and other liabilities | 163 | | | 501 | | | (26) | |
Net cash flows from operating activities | 8,692 | | | 6,224 | | | 6,206 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (6,611) | | | (6,765) | | | (7,364) | |
Acquisitions, net of cash acquired | (122) | | | (2,397) | | | (27) | |
Purchases of marketable securities | (297) | | | (370) | | | (262) | |
Proceeds from sales of marketable securities | 273 | | | 325 | | | 238 | |
Purchases of other investments | (20) | | | (1,323) | | | — | |
Proceeds from other investments | 1,300 | | | 13 | | | 18 | |
Equity method investments | (212) | | | (2,724) | | | (1,617) | |
Other, net | (74) | | | 76 | | | 51 | |
Net cash flows from investing activities | (5,763) | | | (13,165) | | | (8,963) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from issuance of preferred stock | — | | | 3,750 | | | — | |
Preferred stock redemptions | (2,100) | | | — | | | — | |
Preferred dividends | (132) | | | (7) | | | — | |
Common stock purchases | — | | | (126) | | | (293) | |
Proceeds from BHE senior debt | — | | | 5,212 | | | — | |
Repayments of BHE senior debt | (450) | | | (350) | | | — | |
Proceeds from subsidiary debt | 2,409 | | | 2,688 | | | 4,699 | |
Repayments of subsidiary debt | (2,024) | | | (2,841) | | | (1,914) | |
Net (repayments of) proceeds from short-term debt | (276) | | | (939) | | | 684 | |
Purchase of noncontrolling interest | — | | | (33) | | | — | |
Distributions to noncontrolling interests | (488) | | | (122) | | | (23) | |
Contributions from noncontrolling interests | 9 | | | 5 | | | 8 | |
Other, net | (79) | | | (134) | | | (37) | |
Net cash flows from financing activities | (3,131) | | | 7,103 | | | 3,124 | |
| | | | | |
Effect of exchange rate changes | 1 | | | 15 | | | 18 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (201) | | | 177 | | | 385 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 1,445 | | | 1,268 | | | 883 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 1,244 | | | $ | 1,445 | | | $ | 1,268 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)Organization and Operations
Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized as 8 business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables, LLC ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns 4 utility companies in the United States serving customers in 11 states, 2 electricity distribution companies in Great Britain, 5 interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and 1 of the largest residential real estate brokerage franchise networks in the United States.
(2)Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of BHE and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenue and expenses of any acquired entities from the date of acquisition. The Company consolidates variable interest entities ("VIE") in which it possesses both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Intercompany accounts and transactions have been eliminated.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; fair value of assets acquired and liabilities assumed in business combinations; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas, Kern River and AltaLink (the "Regulated Businesses") prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. Restricted amounts are included in restricted cash and cash equivalents and investments and restricted cash and cash equivalents and investments on the Consolidated Balance Sheets.
Investments
Fixed Maturity Securities
The Company's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments and restricted cash and cash equivalents and investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Consolidated Balance Sheets.
Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity investments are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.
Investment gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if the Company intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated fixed maturity investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.
Equity Securities
Investments in equity securities are carried at fair value with changes in fair value recognized in earnings as a component of gains (losses) on marketable securities, net. All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates.
Equity Method Investments
The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and OCI of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, the Company primarily utilizes credit loss history. However, the Company may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 77 | | | $ | 44 | | | $ | 42 | |
Charged to operating costs and expenses, net | 81 | | | 56 | | | 47 | |
Acquisitions | — | | | 5 | | | — | |
Write-offs, net | (50) | | | (28) | | | (45) | |
Ending balance | $ | 108 | | | $ | 77 | | | $ | 44 | |
Derivatives
The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.
For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.
For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
Inventories
Inventories consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $296 million and $382 million as of December 31, 2021 and 2020, respectively, and materials and supplies totaling $826 million and $786 million as of December 31, 2021 and 2020, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $27 million and $10 million higher as of December 31, 2021 and 2020, respectively.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the Regulated Businesses. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity securitiesfunds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are reported atprimarily related to the decommissioning of nuclear generating facilities and obligations associated with its other generating facilities and offshore natural gas pipelines. The fair value. Funds are investedvalue of an ARO liability is recognized in the trustperiod in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
The Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
The Company's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, the Company estimates the fair value of its reporting units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the excess is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2021, 2020 and 2019, the Company did not record any material goodwill impairments.
The Company records goodwill adjustments for changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.
Revenue Recognition
Customer Revenue
The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations. In the event one of the parties to a contract has performed before the other, the Company would recognize a contract asset or contract liability depending on the relationship between the Company's performance and the customer's payment.
Energy Products and Services
A majority of the Company's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. The Company's energy revenue that is nonregulated primarily relates to the Company's renewable energy business.
Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $718 million and $750 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Real Estate Services
The Company's HomeServices reportable segment consists of separate brokerage, mortgage and franchise businesses. Rates charged for brokerage, mortgage and franchise real estate services are established through contractual arrangements that establish the transaction price and the allocation of the price amongst the separate performance obligations.
The full-service residential real estate brokerage business has performance obligations to deliver integrated real estate services including brokerage services, title and closing services, property and casualty insurance, home warranties, relocation services, and other home-related services to customers. All performance obligations related to the full-service residential real estate brokerage business are satisfied in less than one year at the point in time when a real estate transaction is closed or when services are provided. Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Payments for amounts billed are generally due from the customer at closing.
The franchise business operates a network that has performance obligations to provide the right to use certain brand names and other related service marks as well as to provide orientation programs, training and consultation services, advertising programs and other services to its franchisees. The performance obligations related to the franchise business are satisfied over time or when the services are provided. Franchise royalty fees are sales-based variable consideration and are based on a percentage of commissions earned by franchisees on real estate sales, which are recognized when the sale closes. Meetings and training revenue, referral fees, late fees, service fees and franchise termination fees are earned when services have been completed. Payments for amounts billed are generally due from the franchisee within 30 days of billing.
Other Revenue
Energy Products and Services
Other revenue consists primarily of revenue related to power purchase agreements not considered Customer Revenue as they are recognized in accordance with applicableASC 815, "Derivatives and Hedging" and ASC 842, "Leases" and certain non-tariff-based revenue approved by the regulator that is not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."
Real Estate Service
Mortgage and other revenue consists primarily of revenue related to the mortgage business. Mortgage fee revenue consists of amounts earned related to application and underwriting fees, and fees on canceled loans. Fees associated with the origination of mortgage loans are recognized as earned. These amounts are not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging," ASC 825, "Financial Instruments" and ASC 860, "Transfers and Servicing."
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Foreign Currency
The accounts of foreign-based subsidiaries are measured in most instances using the local currency of the subsidiary as the functional currency. Revenue and expenses of these businesses are translated into United States dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in equity as a component of AOCI. Gains or losses arising from transactions denominated in a currency other than the functional currency of the entity that is party to the transaction are included in earnings.
Income Taxes
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state investment guidelinesincome tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company records the deferred income tax assets associated with the state of Iowa net operating loss carryforward as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity due to the long-term related party nature of the income tax receivable.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company's regulated businesses deems probable to be passed on to their customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions. The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely.
The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
(3) Business Acquisitions
BHE GT&S Acquisition
Transaction Description
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") and Carolina Gas Transmission, LLC; 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a 25% economic interest in Cove Point LNG, LP ("Cove Point"), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the United States Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.
On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI was also a party to the Q-Pipe Purchase Agreement, as guarantor for certain provisions regarding the Purchase Price Repayment Amount (as defined below) and other matters.
Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion, which was included in other current assets on the Consolidated Balance Sheet as of December 31, 2020, to Dominion Questar on November 2, 2020. Pursuant to the Q-Pipe Purchase Agreement, Dominion Questar agreed that, if the Q-Pipe Transaction did not close, it would repay all or (depending upon the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021.
On July 9, 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. On July 14, 2021, BHE received the Purchase Price Repayment Amount of approximately $1.3 billion in cash, which was included in proceeds from other investments on the Consolidated Statements of Cash Flows for the year ended December 31, 2021.
Included in BHE's Consolidated Statement of Operations within the BHE Pipeline Group reportable segment for the years ended December 31, 2021 and 2020, is operating revenue of $2,159 million and $331 million, respectively, and net income attributable to BHE shareholders of $316 million and $73 million, respectively, as a result of including BHE GT&S from November 1, 2020. Additionally, BHE incurred $9 million of direct transaction costs associated with the GT&S Transaction that are included in operating expense on the Consolidated Statement of Operations for the year ended December 31, 2020.
Allocation of Purchase Price
BHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the FERC and are restrictedaccounted for use as reimbursementpursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of decommissioningassets and liabilities included in rate base. As such, the Quad Cities Station,fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.
The fair value of BHE GT&S' assets acquired and liabilities assumed not subject to the rate-setting provisions discussed above was determined using an income and cost approach. The income approach is based on significant estimates and assumptions, including Level 3 inputs, which are currently licensed for operation until December 2032.judgmental in nature. The estimates and assumptions include the projected timing and amount of future cash flows, discount rates reflecting the risk inherent in the future cash flows and future market prices. Additionally, the fair value of long-term debt assumed was determined based on quoted market prices, which is considered a Level 2 fair value measurement.
(8)Short-Term Debt and Credit Facilities
The following table summarizes BHE'sthe fair values of the assets acquired and its subsidiaries' availability under their credit facilitiesliabilities assumed as of the acquisition date (in millions):
| | | | | | | | |
| | Fair Value |
| | |
Current assets, including cash and cash equivalents of $104 | | $ | 582 | |
Property, plant and equipment | | 9,264 | |
Goodwill | | 1,741 | |
Regulatory assets | | 108 | |
Deferred income taxes | | 284 | |
Other long-term assets | | 1,424 | |
Total assets | | 13,403 | |
| | |
Current liabilities, including current portion of long-term debt of $1,200 | | 1,616 | |
Long-term debt, less current portion | | 4,415 | |
Regulatory liabilities | | 650 | |
Other long-term liabilities | | 292 | |
Total liabilities | | 6,973 | |
Noncontrolling interest | | 3,916 | |
Net assets acquired | | $ | 2,514 | |
During the year ended December 31, 2021, the Company made revisions to certain contracts and property, plant and equipment related to non-regulated operations, the equity method investment and associated deferred income tax amounts based upon the receipt of additional information about the facts and circumstances that existed as of the acquisition date. Provisional amounts were subject to further revision for up to 12 months following the acquisition date until the related valuations were completed.
Goodwill
The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain items, book and tax goodwill will differ. The amount of tax goodwill is approximately $0.9 billion and will be amortized over 15 years.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of BHE and the amortization of the purchase price adjustments assuming the acquisition had taken place on January 1, 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):
| | | | | | | | | | | |
| 2020 | | 2019 |
| | | |
Operating revenue | $ | 22,581 | | | $ | 21,979 | |
| | | |
Net income attributable to BHE shareholders | $ | 6,800 | | | $ | 3,271 | |
Other
In 2021, the Company completed various other acquisitions of residential real estate brokerage businesses totaling $122 million, net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related to residential real estate brokerage businesses. As a result of the various acquisitions, the Company acquired assets of $54 million, assumed liabilities of $61 million and recognized goodwill of $129 million.
(4)Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable | | | | |
| Life | | 2021 | | 2020 |
Regulated assets: | | | | | |
Utility generation, transmission and distribution systems | 5-80 years | | $ | 90,223 | | | $ | 86,730 | |
Interstate natural gas pipeline assets | 3-80 years | | 17,423 | | | 16,667 | |
| | | 107,646 | | | 103,397 | |
Accumulated depreciation and amortization | | | (32,680) | | | (30,662) | |
Regulated assets, net | | | 74,966 | | | 72,735 | |
| | | | | |
Nonregulated assets: | | | | | |
Independent power plants | 2-50 years | | 7,665 | | | 7,012 | |
Cove Point LNG facility | 40 years | | 3,364 | | | 3,339 | |
Other assets | 2-30 years | | 2,666 | | | 2,320 | |
| | | 13,695 | | | 12,671 | |
Accumulated depreciation and amortization | | | (3,041) | | | (2,586) | |
Nonregulated assets, net | | | 10,654 | | | 10,085 | |
| | | | | |
Net operating assets | | | 85,620 | | | 82,820 | |
Construction work-in-progress | | | 4,196 | | | 3,308 | |
Property, plant and equipment, net | | | $ | 89,816 | | | $ | 86,128 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | MidAmerican | | NV | | Northern | | | | | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | AltaLink | | Other | | Total(1) |
2018: | | | | | | | | | | | | | | | |
Credit facilities(2) | $ | 3,500 |
| | $ | 1,200 |
| | $ | 1,309 |
| | $ | 650 |
| | $ | 231 |
| | $ | 639 |
| | $ | 1,585 |
| | $ | 9,114 |
|
Less: | | | | | | | | | | | | | | | |
Short-term debt | (983 | ) | | (30 | ) | | (240 | ) | | — |
| | (77 | ) | | (345 | ) | | (841 | ) | | (2,516 | ) |
Tax-exempt bond support and letters of credit | — |
| | (89 | ) | | (370 | ) | | (80 | ) | | — |
| | (4 | ) | | — |
| | (543 | ) |
Net credit facilities | $ | 2,517 |
| | $ | 1,081 |
| | $ | 699 |
| | $ | 570 |
| | $ | 154 |
| | $ | 290 |
| | $ | 744 |
| | $ | 6,055 |
|
| | | | | | | | | | | | | | | |
2017: | | | | | | | | | | | | | | | |
Credit facilities | $ | 3,600 |
| | $ | 1,000 |
| | $ | 909 |
| | $ | 650 |
| | $ | 203 |
| | $ | 1,054 |
| | $ | 1,635 |
| | $ | 9,051 |
|
Less: | | | | | | | | | | | | | | | |
Short-term debt | (3,331 | ) | | (80 | ) | | — |
| | — |
| | — |
| | (345 | ) | | (732 | ) | | (4,488 | ) |
Tax-exempt bond support and letters of credit | (7 | ) | | (130 | ) | | (370 | ) | | (80 | ) | | — |
| | (7 | ) | | — |
| | (594 | ) |
Net credit facilities | $ | 262 |
| | $ | 790 |
| | $ | 539 |
| | $ | 570 |
| | $ | 203 |
| | $ | 702 |
| | $ | 903 |
| | $ | 3,969 |
|
| |
(1) | The table does not include unused credit facilities and letters of credit for investments that are accounted for under the equity method. |
(2) Includes the drawn uncommitted credit facilities totaling $39 million at Northern Powergrid.
As of December 31, 2018, the Company was in compliance with the covenants of its credit facilitiesConstruction work-in-progress includes $3.8 billion and letter of credit arrangements.
BHE
BHE has a $3.5$3.2 billion unsecured credit facility expiring in June 2021 with two one-year extension options subject to lender consent. This credit facility, which is for general corporate purposes and also supports BHE's commercial paper program and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at BHE's option, plus a spread that varies based on BHE's credit ratings for its senior unsecured long-term debt securities.
As of December 31, 2018 and 2017, the weighted average interest rate on commercial paper borrowings outstanding was 2.76% and 1.74%, respectively. This credit facility requires that BHE's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter.
As of December 31, 2018 and 2017, BHE had $115 million and $96 million, respectively, of letters of credit outstanding, of which $- million and $7 million as of December 31, 20182021 and 2017,2020, respectively, were issued under the credit facility. These letters of credit primarily support power purchase agreements and debt service requirements at certain subsidiaries of BHE Renewables, LLC expiring through January 2020 and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit priorrelated to the expiration date.construction of regulated assets.
PacifiCorp
(5)Jointly Owned Utility Facilities
PacifiCorp
Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has a $600 million unsecured creditprovided financing for its share of each facility. Operating costs of each facility expiring in June 2021 with a one-year extension option subjectare assigned to lender consent and a $600 million unsecured credit facility expiring in June 2021 with two one-year extension options subject to lender consent. These credit facilities, which support PacifiCorp's commercial paper program, certain series of its tax-exempt bond obligations and provide for the issuance of letters of credit, have variable interest ratesjoint owners based on their percentage of ownership or energy production, depending on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies basednature of the cost. Operating costs and expenses on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.the Consolidated Statements of Operations include the Company's share of the expenses of these facilities.
As
The amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 20182021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | Construction |
| Company | | Facility In | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
PacifiCorp: | | | | | | | |
Jim Bridger Nos. 1-4 | 67 | % | | $ | 1,523 | | | $ | 812 | | | $ | 15 | |
Hunter No. 1 | 94 | | | 489 | | | 221 | | | 8 | |
Hunter No. 2 | 60 | | | 306 | | | 138 | | | 1 | |
Wyodak | 80 | | | 477 | | | 269 | | | 8 | |
Colstrip Nos. 3 and 4 | 10 | | | 260 | | | 161 | | | 3 | |
Hermiston | 50 | | | 185 | | | 99 | | | — | |
Craig Nos. 1 and 2 | 19 | | | 369 | | | 319 | | | — | |
Hayden No. 1 | 25 | | | 77 | | | 47 | | | — | |
Hayden No. 2 | 13 | | | 44 | | | 28 | | | — | |
Transmission and distribution facilities | Various | | 879 | | | 269 | | | 118 | |
Total PacifiCorp | | | 4,609 | | | 2,363 | | | 153 | |
MidAmerican Energy: | | | | | | | |
Louisa No. 1 | 88 | % | | 864 | | | 501 | | | 20 | |
Quad Cities Nos. 1 and 2(1) | 25 | | | 732 | | | 452 | | | 9 | |
Walter Scott, Jr. No. 3 | 79 | | | 949 | | | 518 | | | 15 | |
Walter Scott, Jr. No. 4(2) | 60 | | | 225 | | | 134 | | | 8 | |
George Neal No. 4 | 41 | | | 318 | | | 184 | | | 4 | |
Ottumwa No. 1 | 52 | | | 674 | | | 264 | | | 11 | |
George Neal No. 3 | 72 | | | 528 | | | 286 | | | 9 | |
Transmission facilities | Various | | 263 | | | 100 | | | 4 | |
Total MidAmerican Energy | | | 4,553 | | | 2,439 | | | 80 | |
NV Energy: | | | | | | | |
Navajo | 11 | % | | 5 | | | 5 | | | — | |
Valmy | 50 | | | 394 | | | 309 | | | 1 | |
On Line Transmission Line | 25 | | | 160 | | | 31 | | | 1 | |
Transmission facilities | Various | | 65 | | | 34 | | | — | |
Total NV Energy | | | 624 | | | 379 | | | 2 | |
BHE Pipeline Group: | | | | | | | |
Ellisburg Pool | 39 | % | | 31 | | | 11 | | | 1 | |
Ellisburg Station | 50 | | | 26 | | | 8 | | | 1 | |
Harrison | 50 | | | 53 | | | 18 | | | — | |
Leidy | 50 | | | 132 | | | 46 | | | 7 | |
Oakford | 50 | | | 200 | | | 68 | | | 2 | |
Common Facilities | Various | | 276 | | | 166 | | | — | |
Total BHE Pipeline Group | | | 718 | | | 317 | | | 11 | |
Total | | | $ | 10,504 | | | $ | 5,498 | | | $ | 246 | |
(1)Includes amounts related to nuclear fuel.
(2)Facility in-service and 2017,accumulated depreciation and amortization amounts are net of credits applied under Iowa regulatory arrangements totaling $561 million and $127 million, respectively.
(6) Leases
The following table summarizes the weighted average interest rateCompany's leases recorded on commercial paper borrowings outstanding was 2.85% and 1.83%, respectively. These credit facilities require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0the Consolidated Balance Sheet as of the last day of each quarter.
As of December 31 2018 and 2017, PacifiCorp had $184 million and $230 million, respectively, of fully available letters of credit issued under committed arrangements. As(in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 524 | | | $ | 517 | |
Finance leases | 448 | | | 501 | |
Total right-of-use assets | $ | 972 | | | $ | 1,018 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 577 | | | $ | 569 | |
Finance leases | 463 | | | 514 | |
Total lease liabilities | $ | 1,040 | | | $ | 1,083 | |
The following table summarizes the Company's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 611 | | | $ | 592 | | $ | 623 |
Operating | 161 | | | 151 | | 170 |
Finance: | | | | | |
Amortization | 23 | | | 18 | | 16 |
Interest | 38 | | | 40 | | 41 |
Short-term | 15 | | | 20 | | 7 |
Total lease costs | $ | 848 | | | $ | 821 | | $ | 857 |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 7.6 | | 7.4 | | 7.6 |
Finance leases | 28.1 | | 27.5 | | 28.8 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 4.3 | % | | 4.5 | % | | 5.2 | % |
Finance leases | 8.6 | % | | 8.5 | % | | 8.6 | % |
The following table summarizes the Company's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
Operating cash flows from operating leases | $ | (163) | | | $ | (152) | | | $ | (153) | |
Operating cash flows from finance leases | (38) | | | (40) | | | (42) | |
Financing cash flows from finance leases | (28) | | | (24) | | | (19) | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | |
Operating leases | $ | 119 | | | $ | 83 | | | $ | 82 | |
Finance leases | 2 | | | 19 | | | 14 | |
The Company has the following remaining lease commitments as of December 31, 20182021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 157 | | | $ | 72 | | | $ | 229 | |
2023 | 124 | | | 62 | | | 186 | |
2024 | 93 | | | 62 | | | 155 | |
2025 | 71 | | | 60 | | | 131 | |
2026 | 55 | | | 60 | | | 115 | |
Thereafter | 186 | | | 607 | | | 793 | |
Total undiscounted lease payments | 686 | | | 923 | | | 1,609 | |
Less - amounts representing interest | (109) | | | (460) | | | (569) | |
Lease liabilities | $ | 577 | | | $ | 463 | | | $ | 1,040 | |
(7)Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future regulated rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Asset retirement obligations | 14 years | | $ | 742 | | | $ | 640 | |
Deferred net power costs | 1 year | | 531 | | | 139 | |
Employee benefit plans(1) | 15 years | | 472 | | | 722 | |
Deferred income taxes(2) | Various | | 342 | | | 283 | |
Asset disposition costs | Various | | 285 | | | 347 | |
Demand side management | 10 years | | 211 | | | 197 | |
Unrealized loss on regulated derivative contracts | Various | | 157 | | | 31 | |
Environmental costs | 28 years | | 108 | | | 89 | |
Deferred operating costs | 9 years | | 103 | | | 124 | |
Other | Various | | 1,012 | | | 868 | |
Total regulatory assets | | | $ | 3,963 | | | $ | 3,440 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 544 | | | $ | 283 | |
Noncurrent assets | | | 3,419 | | | 3,157 | |
Total regulatory assets | | | $ | 3,963 | | | $ | 3,440 | |
(1)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
(2)Amounts primarily represent income tax benefits related to certain property-related basis differences and 2017, $170 millionother various differences that were previously passed on to customers and $216 million, respectively,will be included in regulated rates when the temporary differences reverse.
The Company had regulatory assets not earning a return on investment of these letters$1.8 billion and $1.6 billion as of credit support PacifiCorp's variable-rate tax-exempt bondDecember 31, 2021 and 2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 3,185 | | | $ | 3,600 | |
Cost of removal(2) | 26 years | | 2,424 | | | 2,435 | |
Asset retirement obligations | 31 years | | 345 | | | 305 | |
Levelized depreciation | 29 years | | 259 | | | 281 | |
Employee benefit plans(3) | Various | | 243 | | | 187 | |
Other | Various | | 758 | | | 667 | |
Total regulatory liabilities | | | $ | 7,214 | | | $ | 7,475 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 254 | | | $ | 254 | |
Noncurrent liabilities | | | 6,960 | | | 7,221 | |
Total regulatory liabilities | | | $ | 7,214 | | | $ | 7,475 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(3)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be returned to customers in future periods when recognized.
(8)Investments and Restricted Cash and Cash Equivalents and Investments
Investments and restricted cash and cash equivalents and investments consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Investments: | | | |
BYD Company Limited common stock | $ | 7,693 | | | $ | 5,897 | |
Rabbi trusts | 492 | | | 440 | |
Other | 305 | | | 263 | |
Total investments | 8,490 | | | 6,600 | |
| | | |
Equity method investments: | | | |
BHE Renewables tax equity investments | 4,931 | | | 5,626 | |
Iroquois Gas Transmission System, L.P. | 735 | | | 580 | |
Electric Transmission Texas, LLC | 595 | | | 594 | |
JAX LNG, LLC | 92 | | | 75 | |
Bridger Coal Company | 45 | | | 74 | |
Other | 156 | | | 118 | |
Total equity method investments | 6,554 | | | 7,067 | |
| | | |
Restricted cash and cash equivalents and investments: | | | |
Quad Cities Station nuclear decommissioning trust funds | 768 | | | 676 | |
Other restricted cash and cash equivalents | 148 | | | 155 | |
Total restricted cash and cash equivalents and investments | 916 | | | 831 | |
| | | |
Total investments and restricted cash and cash equivalents and investments | $ | 15,960 | | | $ | 14,498 | |
| | | |
Reflected as: | | | |
Other current assets | $ | 172 | | | $ | 178 | |
Noncurrent assets | 15,788 | | | 14,320 | |
Total investments and restricted cash and cash equivalents and investments | $ | 15,960 | | | $ | 14,498 | |
Investments
BHE's investment in BYD Company Limited common stock is accounted for as a marketable security with changes in fair value recognized in net income.
Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and expiredirector compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in March 2019 and $14 million support certain transactions requiredthe Rabbi trusts, net of amounts borrowed against the cash surrender value.
Gains (losses) on marketable securities, net recognized during the period consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Unrealized gains (losses) recognized on marketable securities held at the reporting date | $ | 1,819 | | | $ | 4,791 | | | $ | (290) | |
Net gains recognized on marketable securities sold during the period | 4 | | | 6 | | | 2 | |
Gains (losses) on marketable securities, net | $ | 1,823 | | | $ | 4,797 | | | $ | (288) | |
Equity Method Investments
The Company has invested in wind projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $— million, $2,736 million and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
MidAmerican Funding
MidAmerican Energy$1,619 million in 2021, 2020 and 2019, respectively, and has a $900 million unsecured credit facility expiring in June 2021 with a one-year extension option subject to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Ascommitments as of December 31, 2018, MidAmerican Energy had a $400 million unsecured credit facility expiring November 2019, which it terminated in January 2019.
As of December 31, 2018, the weighted average interest rate on commercial paper borrowings outstanding was 2.49%. The credit facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
NV Energy
Nevada Power has a $400 million secured credit facility expiring in June 2021, and Sierra Pacific has a $250 million secured credit facility expiring in June 2021 each with a one-year extension option subject to lender consent. These credit facilities,satisfaction of certain specified conditions, to provide equity contributions of $356 million in 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
BHE, through separate subsidiaries, owns (i) 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut; (ii) 50% of Electric Transmission Texas, LLC, which owns and operates electric transmission assets in the Electric Reliability Council of Texas footprint; (iii) 50% of JAX LNG, LLC, which is an LNG supplier in Florida serving the growing marine and truck LNG markets; and (iv) 66.67% of Bridger Coal Company ("Bridger Coal"), which is a coal mining joint venture that supplies coal to the Jim Bridger Nos. 1-4 generating facility. Bridger Coal is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are for general corporate purposes and provide forshared with the issuance of letters of credit, have a variable interest rate based on the Eurodollar rate or a base rate, at each of the Nevada Utilities' option, plus a spread that varies based on each of the Nevada Utilities' credit ratings for its senior secured long‑term debt securities. Amounts due under each credit facility are collateralized by each of the Nevada Utilities' general and refunding mortgage bonds. These credit facilities require that each of the Nevada Utilities' ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.joint venture partner.
Northern Powergrid
Northern Powergrid has a £150 million unsecured credit facility expiring in April 2020. The credit facility has a variable interest rate based on sterling London Interbank Offered Rate ("LIBOR") plus a spread that varies based on its credit ratings. The credit facility requires that the ratio of consolidated senior total net debt, including current maturities, to regulated asset value not exceed 0.8 to 1.0 at Northern Powergrid and 0.65 to 1.0 at Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc as of June 30 and December 31. Northern Powergrid's interest coverage ratio shall not be less than 2.5 to 1.0.
AltaLink
ALPAltaLink is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing.
The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable, and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.
AltaLink's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act (Alberta) in respect of rates and terms and conditions of service. The Electric Utilities Act (Alberta) and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.
Under the Electric Utilities Act (Alberta), AltaLink prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides AltaLink with a reasonable opportunity to (i) earn a fair return on equity; and (ii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes (including deemed income taxes) associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. AltaLink's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.
The AESO is an independent system operator in Alberta, Canada that oversees the Alberta Interconnected Electric System ("AIES") and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. AltaLink and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.
The AESO determines the need and plans for the expansion and enhancement of the transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing the current and future transmission system capacity needs of market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally, the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.
Independent Power Projects
The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Walnut Ridge, Pinyon Pines I, Pinyon Pines II, Santa Rita, Independence, Gopher Creek, Flat Top, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Community Solar Gardens, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.
The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Marshall, Grande Prairie, Walnut Ridge, Independence, Pinyon Pines I and Pinyon Pines II independent power projects have obtained authority from the FERC to sell their power using market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines I, Pinyon Pines II, Solar Star 1, Solar Star 2, Topaz and Yuma independent power projects and power marketer CalEnergy, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2019 and an order accepting it was issued in March 2020. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2020 and an order accepting it was issued in December 2020. The Bishop Hill II and Walnut Ridge independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2020 and an order accepting it was issued in March 2021. The Marshall and Grande Prairie independent power projects and power marketer CalEnergy, LLC file together for market power study purposes in the FERC-defined Southwest Power Pool Region. The most recent triennial filing for the Southwest Power Pool Region was made in December 2021 and is awaiting FERC action.
The entire output of Jumbo Road, Santa Rita, Gopher Creek, Flat Top, Alamo 6, Pearl and Power Resources is within the ERCOT and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Light Company within the Hawaii electric grid, which is not a FERC-jurisdictional market and therefore, Wailuku does not require market-based rate authority.
EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utility's avoided cost.
Residential Real Estate Brokerage Company
HomeServices and its operating subsidiaries are regulated by the United States Consumer Financial Protection Bureau which enforces the Truth In Lending Act ("TILA"), the Equal Credit Opportunity Act ("ECOA") and the Real Estate Settlement Procedures Act ("RESPA"); by the United States Federal Trade Commission with respect to certain franchising activities; by the United States Department of Housing and Urban Development, which enforces the Fair Housing Act ("FHA"); and by state agencies where its subsidiaries operate. TILA and ECOA regulate lending practices. FHA prohibits housing-related discrimination on the basis of race, color, national origin, religion, sex, familial status, and disability. RESPA regulates real estate settlement services including real estate closing practices, lender servicing and escrow account practices and business relationships among settlement service providers and third parties to the transaction.
REGULATORY MATTERS
In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further information regarding the general regulatory framework.
PacifiCorp
Utah
In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million of deferred net power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to current rates. The UPSC approved the request in February 2021 for rates effective March 1, 2021.
In March 2021, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $2 million of deferred net power costs from customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflected a $36 million reduction, or 1.7% decrease compared to current rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain load related data reflected in the initial application. The updated recovery request reflects a $31 million reduction, or 1.5%, decrease compared to current rates. In January 2022, PacifiCorp filed an uncontested stipulation agreement providing for full recovery of the requested $7 million. The UPSC approved the stipulation agreement as filed in February 2022.
In August 2021, PacifiCorp filed an application with the UPSC for alternative cost recovery of a major plant addition to recover the incremental revenue requirement related to the delayed portions of the Pryor Mountain and TB Flats wind-powered generating facilities that are not currently reflected in rates from the last general rate case. PacifiCorp's request would result in a net decrease of $4 million, or 0.2%, in base rates effective January 1, 2022. Requested recovery of $7 million for the capital related cost is offset by $7 million related to forecast PTCs and $4 million in net power cost savings with actual PTCs and net power cost savings to be trued-up in the EBA. In December 2021, the UPSC concluded PacifiCorp's request did not qualify for recovery under the major plant additions statute and denied the application.
In August 2021, PacifiCorp filed an application with the UPSC for approval of its Electric Vehicle Infrastructure Program as provided for by Utah House Bill 396 ("HB 396"), Electric Vehicle Charging Infrastructure Amendments. The filing details how PacifiCorp proposes to invest the $50 million authorized by HB 396 to support the development of electric vehicle infrastructure in Utah. In November 2021, PacifiCorp reached a settlement stipulation with most of the intervening parties resolving all issues. The remaining intervening parties are not signatories but did not oppose the stipulation. The new program provides funding for both utility-owned charging equipment and make-ready infrastructure; establishes a new tariff for charging rates at PacifiCorp-owned stations, initially set at 45 cents per kilowatt-hour for the general public with a 40% discount for PacifiCorp's Utah customers; creates a new surcharge to collect $50 million over 10 years from Utah customers to fund the program; establishes annual reporting to the UPSC with a program review every three years; and extends the residential time-of-use pilot rates. The surcharge replaced the existing Sustainable Transportation and Energy Plan cost adjustment that expired on December 31, 2021. In December 2021, the UPSC approved the settlement stipulation, resulting in a decrease of $5 million, or 0.2%, compared to current rates effective January 1, 2022.
Oregon
In February 2020, PacifiCorp filed a general rate case and in December 2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind-powered generating facilities, new wind-powered generating facilities and certain other new investments that had not been placed in-service at the time of the filing. Additional compliance filings have been made to include investments in rates concurrent with when they were placed in-service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind-powered generating facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind-powered generating facility and the Pryor Mountain new wind-powered generating facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021. In July 2021, a deferral for resources not placed in-service by June 30, 2021 was filed for consideration in a future rate proceeding.
In July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The application requests an initial rate increase of $35 million, or 2.8%, effective January 1, 2022, to recover the incremental costs from those approved in the last general rate case.
In April 2021, PacifiCorp submitted its annual TAM filing in Oregon requesting an increase of $1 million, or 0.1%, effective January 1, 2022, based on forecast net power costs and loads for the calendar year 2022. In July 2021, PacifiCorp filed a reply with an amended net power costs which updated its 2022 TAM to a $2 million rate increase. In November 2021, the OPUC approved PacifiCorp's 2022 TAM, subject to adjustments, reducing PacifiCorp's requested net power cost amount and resulting in an overall annual rate decrease of approximately $15 million, or 1.2 %, effective January 1, 2022.
In May 2021, Oregon's governor signed Oregon House Bill 2165 requiring electric companies to collect funding to support and integrate transportation electrification. In July 2021, Oregon's governor signed Oregon House Bill 3141 addressing changes related to public purpose and energy efficiency rates. In November 2021, PacifiCorp filed an advice letter to address the legislative changes adopted in House Bills 2165 and 3141. In December 2021, the OPUC approved the advice filing. The filing resulted in an overall rate increase of approximately $5 million, or 0.4%, effective January 1, 2022.
In July 2021, Oregon's governor signed Oregon House Bill 2739 requiring electric companies to collect an additional $10 million per calendar year for low-income electric bill payment and crisis assistance beginning January 1, 2022. In November 2021, PacifiCorp filed an advice letter to revise the rates, and the OPUC approved the advice filing in December 2021. The filing resulted in an overall rate increase of $4 million, or 0.3%, effective January 1, 2022, representing PacifiCorp's share.
Wyoming
In September 2018, PacifiCorp filed an application for depreciation rate changes with the WPSC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities and removal of Cholla Unit 4. In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent written order in December 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application was held in July 2021. In September 2021, the WPSC approved in a bench decision PacifiCorp's application to defer depreciation expense incurred from January 1, 2021 through June 30, 2021 subject to certain offsetting cost savings during the relevant period. A final order is pending. The WPSC will address recovery of the deferred costs in a future general rate case.
In March 2020, PacifiCorp filed a general rate case with the WPSC which reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested a revision to the ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million, or 1.3%, and reflected an update to the rate mitigation measures for using 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and were completed in March 2021. In May 2021, the WPSC approved a $7 million base revenue requirement increase that includes the Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and rate design proposals to be offset by returning the remaining 2017 Tax Reform benefits to customers over the next three years. The WPSC also approved revisions to the ECAM to adjust the sharing band from 70/30 to 80/20 and to include PTCs within the mechanism. PacifiCorp's proposals for extended recovery of the depreciation of certain coal-fueled generation units and use of remaining 2017 Tax Reform benefits to buy down certain plant balances were denied. The WPSC decision resulted in an overall net decrease of 3.5% effective July 1, 2021. A final written order was issued in July 2021.
In April 2021, PacifiCorp filed its annual ECAM and REC and Sulfur Dioxide Revenue Adjustment Mechanism application with the WPSC requesting to refund $15 million of deferred net power costs and RECs to customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflects a 2.4% decrease compared to current rates. PacifiCorp requested an interim rate effective July 1, 2021, which was approved by the WPSC in June 2021. PacifiCorp filed an all-party stipulation in October 2021. A hearing on the stipulation was held in November 2021 during which the WPSC approved the all-party stipulation in a bench decision and the final order was issued in February 2022.
Washington
In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase had a requested effective date of January 1, 2022. In November 2021, PacifiCorp reached a proposed settlement with most of the parties, which includes an agreement to adjust the PTC rate in base rates and apply a production factor and to include a net power cost update as part of the compliance filing. A hearing was held in January 2022 and a WUTC decision is pending.
Idaho
In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020, a 1.1% decrease compared to current rates. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs, changes in RECs, and a resource tracking mechanism to match costs with the benefits of new wind and wind repowering projects until they are reflected in base rates. In May 2021, PacifiCorp updated the requested recovery to correct for certain load related data reflected in the initial application, and the IPUC approved recovery of $10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2021.
In May 2021, PacifiCorp filed a general rate case with the IPUC requesting a $19 million, or 7.0%, revenue requirement increase effective January 1, 2022. This is the first general rate case PacifiCorp has filed in Idaho since 2011. The rate case includes recovery of Energy Vision 2020 investments, the Pryor Mountain wind-powered generating facility, repowered Foote Creek, new investment in transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested recovery of the decommissioning and closure costs associated with the early retirement of Cholla Unit 4. PacifiCorp filed an all-party settlement with the IPUC in October 2021, resolving all issues in the case. The settlement provides an $8 million, or 2.9%, overall increase, which will be offset in part by a refund of deferred income tax savings over two years, resulting in a net increase of $4 million, or 1.4%. In December 2021, the IPUC issued an order approving the settlement with rates effective January 1, 2022.
California
California SB 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in March 2021 for which it received approval in July 2021.
In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $7 million, or 6.7%, decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. In March 2021, the CPUC approved the rate change related to GHG allowances and in November 2021, approved updated rates for energy costs as filed.
In August 2021, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application included a $5 million rate decrease associated with lower energy costs, partially offset by an increase of $3 million to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. PacifiCorp's application would result in a rate decrease of $2 million, or 1.9%, effective January 1, 2022. In January 2022, PacifiCorp filed an amended application, per CPUC direction, to reflect ECAC rates which had been approved since the original filing was made in August 2021. The amended application included an over $3 million rate increase associated with higher energy costs, as well as the previously sought increase of $3 million to recover GHG allowances. PacifiCorp's application would result in a rate increase of $7 million, or 6.6%. PacifiCorp anticipates interim approval of its GHG rates in March 2022 based on a settlement stipulation filed by the parties.
FERC Show Cause Order
On April 15, 2021, the FERC issued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain NERC reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of $42 million as a result of the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. In July 2021, PacifiCorp filed its answer to the FERC's show cause order denying the alleged violation of certain NERC reliability standards. The FERC Office of Enforcement staff replied in September 2021. A decision by the FERC is pending.
MidAmerican Energy
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all of Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy secured sufficient safe harbor equipment necessary to remain eligible for 60% PTCs under current tax law and has asked the IUB to issue a final decision on the application by October 2022 to allow MidAmerican Energy to construct Wind PRIME and place it in-service by the end of 2024.
Natural Gas Purchased for Resale
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the year ended December 31, 2021.
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law ensures MidAmerican Energy, as an incumbent electric transmission owner, has the legal right to construct, own and maintain transmission lines that have been approved by the MISO (or another federally registered planning authority) in MidAmerican Energy's service territory. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for construction that it intends to construct, own and maintain the electric transmission line. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the electric transmission line. Legal challenges have been brought against similar laws in other states, but courts that have ruled on such cases have upheld the states' laws. In October 2020, a lawsuit challenging the law was filed in Iowa by national transmission interests. The suit raises issues specific to Iowa law, and the State of Iowa is defending the law in the suit. MidAmerican Energy intervened in the suit and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021, and the national transmission interests appealed. The parties are in the process of briefing the court. A date for oral arguments has not been set and is not expected until third quarter 2022.
Renewable Subscription Program
In December 2020, MidAmerican Energy filed with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customers with the opportunity to meet their future energy growth above baseline levels with renewable energy from specific additions to MidAmerican Energy wind-powered generation and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the RSP, MidAmerican Energy would own the facilities, retain PTCs and other tax benefits associated with the facilities and include all revenues and costs from the program in its Iowa-jurisdictional results of operation, but renewable attributes from the facilities would be specifically assigned to subscribing customers. In June 2021, the IUB issued an order rejecting the RSP and, in July 2021, issued an order denying MidAmerican Energy's request for reconsideration thereof and affirming its June 2021 order. In the July order, the IUB expressed its view that the RSP-related generating facilities and associated PTCs, costs and revenues must be removed from MidAmerican Energy's revenue sharing calculations. In June 2021, the IUB issued an order opening a docket to review MidAmerican Energy's revenue sharing calculations. That docket remains open.
NV Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Reviews
In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2020, the PUCN issued a final order directing Nevada Power to continue the earning sharing mechanism subject to any modifications made to the earning sharing mechanism pursuant to an alternative ratemaking ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory rate review. The new rates were effective on January 1, 2021.
Price Stability Tariff
In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option for renewable resources. The CPST provides for an energy rate that would replace the BTER and DEAA. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and an updated CPST with the PUCN. The enrollment period for the tariff has ended with no customers having enrolled.
Natural Disaster Protection Plan
The Nevada Utilities submitted their initial NDPP to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. The Bureau of Consumer Protection filed a petition for judicial review with the district court in November 2020.In December 2020, the PUCN issued a second modified final order approving the NDPP, as modified, and reopened its investigation and rulemaking on SB 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an order is expected in 2022. In March 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. The Nevada Utilities filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, the Nevada Utilities and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
SB 448
SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage, and accelerate transportation electrification within the state of Nevada. In September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of high-voltage transmission infrastructure, Greenlink North among others, that will be placed into service no later than December 31, 2028, and requires the IRP to include at least one scenario that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. The plan establishes requirements for the contents of the transportation electrification investment as well as requirements for review, cost recovery and monitoring. The plan covers an initial period beginning January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN issued an order granting the application and accepting the Economic Recovery Transportation Electrification Plan with some modifications. The PUCN opened rulemakings to address other regulations that resulted from SB 448. These rulemakings are ongoing.
ON Line Temporary Rider ("ONTR")
In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR with corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a result of the ON Line cost reallocation as well as the related on-going reallocated revenue requirement. Sierra Pacific's application would, if approved by the PUCN as filed, result in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022. In November 2021, intervening parties filed motions to dismiss the filing which were denied by the PUCN in December 2021. A hearing with the PUCN for the application was held in February 2022 and an order is expected in the first quarter of 2022.
Northern Powergrid Distribution Companies
GEMA, through the Ofgem is undertaking its scheduled review of the electricity distribution price control, to put in place a new price control at the end of the current period, which ends March 2023.
The new price control ("ED2") will run for five years, from April 2023 to March 2028. In December 2020 and March 2021, GEMA published its decision on the methodology it will use to set ED2. This confirmed that Ofgem will maintain many aspects of the current price control and that the changes being made will generally follow the template that was set by the price controls implemented in April 2021 for transmission and gas distribution in Great Britain. Specific changes include some new service standard incentives and mechanisms to adjust cost allowances in specific circumstances, while others will be discontinued, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds.
Ofgem published a working assumption of 4.65% for the allowed cost of equity (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs, CPIH). When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, this working assumption is approximately two percentage points lower than the current cost of equity for electricity distribution. Ofgem will set a final value in its determinations in late 2022.
In December 2021, Northern Powergrid published and filed its business plan with Ofgem, setting out its detailed approach for 2023-2028 including the cost allowances this approach would require. Ofgem is expected to publish draft determinations of the new price control in mid-2022 with final determinations expected in late 2022.
BHE Pipeline Group
BHE GT&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of approximately $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of approximately $4 million and a decrease in annual depreciation expense of approximately $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.
Northern Natural Gas
In January 2019, FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC Section 5 order, Northern Natural Gas filed a cost and revenue study in April 2019. In July 2019, Northern Natural Gas filed a Section 4 rate case requesting increases in its transportation and storage rates. In January 2020, the FERC approved Northern Natural Gas' filing to implement its interim rates subject to refund, effective January 1, 2020. In June 2020, a settlement agreement was filed with the FERC, resolving the Section 5 investigation and Section 4 rate case and providing for increased service rates and depreciation rates. Market Area transportation reservation rates increased 28.5% and storage reservation rates increased 67.0% from the rates that were in effect in 2019. Depreciation rates are 2.3% for onshore transmission plant, 2.95% for LNG storage plant, 13.0% for intangible plant, and 2.75% for general plant. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2022, subject to certain exceptions, as well as provides for minimum annual maintenance capital spending. The settlement rates were implemented May 1, 2020, and the Company's provision for rate refunds for January 2020 through April 2020 totaled $69 million. The FERC approved the settlement in September 2020, and rate refunds to customers were processed in early October 2020.
BHE Transmission
AltaLink
Tariff Refund Application
In January 2021, driven by the pandemic and economic shutdown that negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consisted of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation.
In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 customer tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provided Alberta customers with immediate tariff relief in 2021. The approved 2021 tariff refund included a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 were proposed in AltaLink's 2022-2023 GTA.
2019-2021 General Tariff Application
In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide a further tariff reduction over the three-year period by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In April 2019, AltaLink filed an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.
In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the three-year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023.
In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.
In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership. The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.
In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year-over-year increase of approximately 2% in 2022 and 2023 revenue requirements. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively.
In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. The amended application requested the approval of transmission tariffs of C$820 million and C$843 million for 2022 and 2023, respectively. In November 2021, the AUC approved the 2022 interim refundable transmission tariff at C$57 million per month effective January 2022.
In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. The AUC approved a two-year total revenue requirement of C$1.7 billion as compared to AltaLink's requested revenue requirement of C$1.8 billion. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta.
2022 Generic Cost of Capital Proceeding
In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding considered the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the AUC requested participants to submit comments that addressed the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.
In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there was insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.
In March 2021, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta customers.
2023 Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the 2023 generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. Due to ongoing capital market uncertainties related to COVID-19, the AUC is considering extending the 2022 approved cost of capital parameters, of 8.5% return on equity and 37% deemed equity ratio, to 2023. The AUC intends to issue a decision on the first stage by March 31, 2022. With respect to the second stage, the AUC plans to commence the 2024 GCOC proceeding to establish a formula-based approach in the third quarter of 2022 and to conclude in the second quarter of 2023.
2019 Deferral Accounts Reconciliation Application
In October 2020, AltaLink filed its application with the AUC, which included 10 projects with total gross capital additions of C$129 million, including applicable AFUDC. In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128 million of the gross capital project additions. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and annual structure payments as filed. AltaLink filed its compliance filing in April 2021. In May 2021, the AUC issued its decision approving the compliance filing as filed.
BHE U.S. Transmission
A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review scheduled for no later than February 1, 2023. In January 2021, the Public Utilities Commission of Texas ("PUCT") approved ETT's request to suspend a base regulatory rate review filing scheduled for February 2021. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007. In June 2018, the PUCT approved ETT's application to reduce its transmission revenue by $28 million to reflect the lower federal income tax rate due to 2017 Tax Reform with the amortization of excess accumulated deferred federal income taxes expected to be addressed in the next base rate case.
ENVIRONMENTAL LAWS AND REGULATIONS
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The Company has cumulative investments in (i) owned wind, solar and geothermal generating facilities of $30.1 billion and (ii) wind tax equity investments of $5.9 billion. The Company plans to spend an additional $7.8 billion on the construction of renewable generating facilities and repowering certain existing wind-powered generating facilities through 2024. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's renewable generation-related capital expenditures.
Climate Change
In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of GHG emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders' Summit held in April 2021, President Biden announced new climate goals to cut GHG emissions 50%-52% economy-wide by 2030 compared to 2005 levels and to reach 100% carbon pollution-free electricity by 2035.
GHG Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fueled with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred, and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. The EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, the EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. The EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule on April 5, 2021.
Affordable Clean Energy Rule
In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the United States Supreme Court in February 2016 while litigation proceeded. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan, which was intended to achieve an overall reduction in carbon dioxide emissions from existing fossil-fueled electric generating units of 32% below 2005 levels. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule, which fully replaced the Clean Power Plan. In the Affordable Clean Energy rule, the EPA determined that the best system of emissions reduction for existing coal-fueled generating facilities is limited to actions that can be taken at a point source facility, specifically heat rate improvements and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. States have until July 2022 to submit compliance plans to the EPA. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the United States Supreme Court agreed to hear an appeal of that decision. Arguments in the case will be held February 28, 2022, and a decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act is expected by June 2022. Until litigation is exhausted and the EPA indicates its course of action in response to this decision, the full impacts on the Registrants cannot be determined. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including generating facility efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advanced customer energy efficiency programs.
New Source Performance Standards for Methane Emissions
In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution reinstated the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA proposed rules that would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposals would expand and strengthen emissions reduction requirements for new, modified and reconstructed oil and natural gas sources and would require states to reduce methane emissions from existing sources nationwide. The EPA took comment on the proposed rules through January 31, 2022. The EPA intends to issue a supplemental proposal in 2022, including draft regulatory text, and plans to finalize the rules by the end of 2022. Until the rules are finalized, the relevant Registrants cannot determine the full impacts of the proposed rule.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:
•In June 2013, Nevada SB 123 was signed into law. Among other things, SB 123 and regulations thereunder required Nevada Power to file with the PUCN an emissions reduction and capacity replacement plan by May 1, 2014. In May 2014, Nevada Power filed its emissions reduction capacity replacement plan. The plan provided for the retirement or elimination of 300 MWs of coal-fueled generating capacity by December 31, 2014, another 250 MWs of coal-fueled generating capacity by December 31, 2017, and another 250 MWs of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also sets forth the expected timeline and costs associated with decommissioning coal-fueled generating units that will be retired or eliminated pursuant to the plan. The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by Nevada Power. The PUCN may approve variations to Nevada Power's resource plans relative to requirements under SB 123. Refer to Nevada Power's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the ERCR Plan.
•Under the authority of California's Global Warming Solutions Act, which includes a series of policies aimed at returning California GHG emissions to 1990 levels by 2020, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations were imposed on entities beginning in 2013. PacifiCorp is subject to the cap-and-trade program as a retail service provider in California and an importer of wholesale energy into California. In 2015, California's governor issued an executive order to reduce emissions to 40% below 1990 levels by 2030 and 80% by 2050. In September 2016, California SB 32 was signed into law establishing GHG emissions reduction targets of 40% below 1990 levels by 2030.
•The states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electricity generating resources. Under the laws in California and Oregon, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. In September 2018, the Washington Department of Commerce amended the emissions performance standards to provide that GHG emissions for base load electricity generating resources must not exceed 925 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.
•In September 2016, the Washington Department of Ecology issued a final rule regulating GHG emissions from sources in Washington. The rule regulates GHG including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride beginning in 2017 with three-year compliance periods thereafter (i.e., 2017-2019, 2020-2022, etc.). Under the rule, the Washington Department of Ecology established GHG emissions reduction pathways for all covered entities. Covered entities may use emission reduction units, which may be traded with other covered entities, to meet their compliance requirements. PacifiCorp's resource that is covered under the rule includes the Chehalis generating facility, which is a natural gas combined-cycle generating facility located in Washington state. PacifiCorp received its baseline emission order on December 17, 2017, which specified the emission reduction requirements for the Chehalis generating facility every three years beginning in 2017. The reduction requirements average 1.7% per year. However, the Washington Department of Ecology suspended the compliance obligations of the Clean Air Rule after a Thurston County Superior Court judge ruled the state lacks authority to mandate reductions from indirect emitters. On January 16, 2020, the Washington Supreme Court affirmed that the rule limits the applicability of emission standards to actual emitters and cannot be expanded to non-emitters. The court also found that the rule itself is severable, so that the Washington Department of Ecology may continue to enforce the rule as it applies to emitters. The case was remanded for further proceedings. Pending further action by the lower court, the rule itself remains suspended, but entities subject to the rule are required to continue reporting emissions.
•The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to cap and reduce power sector GHG emissions in 11 Eastern states, required, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. Following a program review in 2012, the nine Regional Greenhouse Gas Initiative states implemented a new 2014 cap which was approximately 45% lower than the 2012-2013 cap. The cap is reduced each year by 2.5% from 2015 to 2020. In December 2017, an updated model rule was released by the Regional Greenhouse Gas Initiative states which includes an additional 30% regional cap reduction between 2020 and 2030.
•On May 7, 2019, Washington's governor signed into law the Clean Energy Transformation Act ("CETA") (SB 5116), which requires utilities to eliminate coal generation from Washington customers' allocation of electricity and requires all sales of electricity to Washington retail electric customers to be greenhouse gas neutral by 2030, and non-emitting and electric generation from renewable resources to supply 100% of retail sales by 2045. Electric utilities must also eliminate from rates coal-fueled resources by December 31, 2025. PacifiCorp submitted its first Clean Energy Implementation Plan, demonstrating how it plans to meet the targets established in the law, on December 30, 2021.
•On July 27, 2021, Oregon's governor signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baseline of the average of 2010, 2011 and 2012 emissions and requires utilities to meet the following reductions from that baseline: 80% by 2030, 90% by 2035 and 100% by 2040. The law also requires by 2030 at least 10% of the aggregate electrical capacity of utilities to be comprised of small-scale renewable resources with a capacity of 20 MWs or less by 2030. No earlier than second quarter 2023, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets. While the regulatory framework is still being developed, PacifiCorp anticipates coordinating the submittals of its clean energy plan and IRP in 2023.
•On May 17, 2021, the state of Washington passed the Climate Commitment Act (SB 5126), which creates an economy-wide cap-and-trade program to reduce GHG emissions. Under the Climate Commitment Act, the Washington Department of Ecology must establish progressively declining annual allowance budgets for emissions of GHG beginning January 1, 2023. PacifiCorp is subject to the Climate Commitment Act as an importer and generator of electricity in Washington.
•Illinois enacted the Climate and Equitable Jobs Act in September 2021, a wide-ranging energy omnibus bill touching on nearly all aspects of state energy policy. Among other things, the act codifies Illinois' policy to rapidly transition to 100% clean energy by 2050, which is achieved, in part, by preserving existing nuclear generation, doubling investment in wind and solar projects, and investigating alternative technologies, such as energy storage.
•Wisconsin, through a 2019 executive order, established the Wisconsin Office of Sustainability and Clean Energy, which is charged with achieving a goal of 100% carbon-free electricity by 2050. To assist reaching that goal, Wisconsin's governor also established the Governor's Task Force on Climate Change, to solicit stakeholder input and develop policy recommendations to meaningfully mitigate and adapt to the effects of climate change. Aggressive utility carbon reduction goals are among the task force's recommendations, including a goal of reducing net energy-sector carbon emissions to 100% below 2005 levels by 2050.
•Minnesota enacted an economy-wide requirement to reduce GHG emissions at least 80% below 2005 levels by 2050. The state codified a preference for using clean energy resources to meet its electricity demand, and that preference served as a basis for the state's largest utilities to commit to 100% carbon-free electricity by 2050. Minnesota's governor recently accelerated the state's timeline by proposing a standard requiring utilities to provide 100% carbon-free electricity by 2040, a decade earlier than current commitments. The accelerated standard is currently being considered by the state's legislature.
Renewable Portfolio Standards
Each state's RPS described below could significantly impact the relevant Registrant's consolidated financial results. Resources that meet the qualifying electricity requirements under each RPS vary from state to state. Each state's RPS requires some form of compliance reporting, and the relevant Registrant can be subject to penalties in the event of noncompliance. Each Registrant believes it is in material compliance with all applicable RPS laws and regulations.
In 1983, Iowa became the first state in the United States to adopt a RPS requiring the state utilities to own or to contract for a combined total of 105 MWs of renewable generating capacity and associated energy production. The IUB allocated the 105-MW requirement between the two utilities in Iowa based on each utility's percentage of their combined estimated Iowa retail peak demand in 1990 resulting in MidAmerican Energy being allocated a RPS requirement of 55.2 MWs. The utility must meet its RPS obligation by either owning renewable energy production facilities located in Iowa or entering into long-term contracts to purchase or wheel electricity from renewable production facilities located in the utility's service area.
Since 1997, NV Energy has been required to comply with a RPS. In November 2020, Nevada voters approved a constitution amendment that requires the state to obtain at least half its electricity from renewable sources by 2030. Beginning in 2022, the state must get 22% of its electricity from renewable sources. That percentage is increased incrementally over eight years up to the 50% threshold by 2030. The state's previous RPS required utilities to obtain 25% of their electricity from renewable sources by 2025.
Utah's Energy Resource and Carbon Emission Reduction Initiative provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere within the WECC, and RECs can be used.
The Oregon Renewable Energy Act ("OREA") provides a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the law, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, and 20% in 2020 through 2024. In March 2016, Oregon SB 1547-B, the Clean Electricity and Coal Transition Plan, was signed into law. SB 1547-B requires coal-fueled resources be eliminated from Oregon's allocation of electricity by January 1, 2030 and increases the current RPS target from 25% in 2025 to 50% by 2040. SB 1547-B also implements new REC banking provisions, as well as the following interim RPS targets: 27% in 2025 through 2029, 35% in 2030 through 2034, 45% in 2035 through 2039, and 50% by 2040 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause (the RAC) to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.
Washington's Energy Independence Act establishes a renewable energy target for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020 and each year thereafter. In April 2013, Washington SB 5400 was signed into law. SB 5400 expands the geographic area in which eligible renewable resources may be located to beyond the Pacific Northwest, allowing renewable resources located in all states served by PacifiCorp to qualify. SB 5400 also provides PacifiCorp with additional flexibility and options to meet Washington's renewable mandates. Washington's recently enacted CETA, among other things, requires Washington utilities to be carbon neutral by January 1, 2030 and institutes a planning target of 100% non-emitting generation by 2045. Electric utilities must also eliminate from rates coal-fueled resources by December 31, 2025.
The California RPS required all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020. In October 2015, California SB 350 became law and increased the RPS target to 50% by December 31, 2030. The state's RPS was further expanded in September 2018, when California SB 100, the 100 Percent Clean Energy Act of 2018 was signed into law. In addition to requiring retail sellers to meet a RPS target of 60% by 2030, SB 100 enabled a longer-term planning target for 100% of total California retail sales to come from eligible renewable energy resources and zero-carbon resources by December 31, 2045. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three product content categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers.
Clean Air Act Regulations
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.
On June 4, 2018, the EPA published final ozone designations for much of the United States. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. The EPA must finalize the proposed rules by December 15, 2022. In addition, the EPA must, by December 15, 2022, approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. Also in January 2022, the EPA initiated interagency review of a new rule to address "good neighbor" SIP provisions. While the interagency review is not yet complete and the proposed rule is not available for public comment, the EPA has indicated the action would apply in certain states for which the EPA has either disapproved a "good neighbor" SIP submission or has made a finding of failure to submit such a plan for the 2015 ozone NAAQS. The action would determine whether and to what extent ozone-precursor emissions reductions are required to eliminate significant contribution or interference with maintenance from upwind states that are linked to air quality problems in other states for the 2015 standard. Until the EPA takes final action consistent with this decree, impacts to the relevant Registrants cannot be determined.
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 100 parts per billion. In February 2012, the EPA published final designations indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide NAAQS. On April 6, 2018, the EPA issued a decision to retain the 2010 nitrogen dioxide NAAQS without revision.
In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO2 NAAQS without revision.
The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations required the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate) are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.
In December 2012, the EPA finalized more stringent fine particulate matter NAAQS, reducing the annual standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. The EPA did not set a separate secondary visibility standard, choosing to rely on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014, the EPA issued final area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the relevant Registrant operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the relevant Registrant does not anticipate that any impacts of the revised standard will be significant. In December 2020, the EPA finalized its decision to retain, without revision, the existing primary and secondary standards for particulate matter. In June 2020, the EPA proposed a determination of attainment for the 2006 24-hour fine particulate matter for Salt Lake City and Provo, Utah, serious nonattainment areas. The determination is based upon quality-assured, quality controlled and certified ambient air monitoring data showing that the area has attained the 2006 standard based on the 2017-2019 monitoring. The comment period for the proposal ended in August 2020. In October 2021, the EPA issued a draft policy assessment for reconsideration on the 2020 particulate matter determination and accepted comments through December 2021. Until the rule and its reconsideration are finalized, the relevant Registrants cannot determine the impact on their operations.
In December 2014, the Utah SIP for fine particulate matter was adopted by the Utah Air Quality Board. PacifiCorp's Lake Side, Lake Side 2, Gadsby Steam and Gadsby Peakers generating facilities operate within nonattainment areas for fine particulate matter; however, the SIP did not impose significant new requirements on PacifiCorp's impacted generating facilities, nor did the EPA's comments on the Utah SIP identify requirements for PacifiCorp's existing generating facilities that would have a material impact on its consolidated financial results.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012 and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.
In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112, reaffirming its determination made in the 2016 Supplemental Finding that it was appropriate and necessary to regulate hazardous air pollutants while expanding the rationale supporting that conclusion. The EPA also proposed to retain the 2020 risk and technology review for MATS. The 2020 risk and technology review found that current standards are protective of human health with an adequate margin of safety and that there were no developments in practices, processes or standards warranting a revision of the standard. The EPA requests comments with information regarding technology and fleet emissions performance to inform any future action related to the risk and technology review. Any additional review of the risk and technology review will be separate from this proposal. Impacts from the rule as proposed are expected to be minimal. However, until the agency takes final action on the proposal, the relevant Registrants cannot fully determine the effects of the changes to the MATS rule.
In March 2020, the D.C. Circuit issued an opinion in Chesapeake Climate Action Network v. EPA regarding consolidated challenges to the EPA's startup and shutdown provisions contained in the 2012 MATS rule. The MATS rule's provisions governing startup and shutdown require electric generating units comply with work practice standards as opposed to numerical limits during these periods. The EPA denied petitions for reconsideration of these provisions in 2016 and environmentalists challenged this denial. The D.C. Circuit vacated the reconsideration denials, remanding the petition to the EPA for further action. The court did not make a determination on the merits of the arguments concerning the EPA's legal authority to set work practice standards. The existing work practice standards and the alternate definition for when startup ends continue to be applicable. Until the EPA finalizes action to respond to the court's order, the relevant Registrants cannot fully determine the impacts of the remand.
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.
The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit Court. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit Court issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from generating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at generating facilities in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021, a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and BHE Renewables operates natural gas-fueled generating facilities in Texas, Illinois and New York, which are subject to the CSAPR. MidAmerican Energy has installed emissions controls at its coal-fueled generating facilities to comply with the CSAPR and may purchase emissions allowances to meet a portion of its compliance obligations. The cost of these allowances is subject to market conditions at the time of purchase and historically has not been material. MidAmerican Energy believes that the controls installed to date are consistent with the reductions to be achieved from implementation of the rule. None of PacifiCorp's, Nevada Power's or Sierra Pacific's generating facilities are subject to the CSAPR. However, in a Notice of Data Availability published in the January 6, 2017 Federal Register, the EPA provided preliminary estimates of which upwind states may have linkages to downwind states experiencing ozone levels at or exceeding the 2015 ozone NAAQS of 70 parts per billion, and, using similar methodology to that in the CSAPR, indicated that Utah and Wyoming could have an obligation under the "good neighbor" provisions of the Clean Air Act to reduce NOx emissions. Until such time as a rule is finalized, the relevant Registrants cannot determine whether additional action may be required.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions ("CAMX") dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon generating facility federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington generating facilities. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation. After review of the rule by the Biden administration, the EPA determined it would defend the rule and briefing in the case occurred in January and February 2022. A date for oral arguments has not been scheduled.
The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The EPA, United States Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement. The EPA did not proceed with final approval of the settlement agreement for Wyodak and is currently engaged with Wyoming and PacifiCorp concerning alternative paths for resolution. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit allowing Naughton Unit 3 to operate on coal through 2017 and providing for natural gas conversion of the unit in 2018. In 2017, the department approved an extension of the compliance date for Naughton Unit 3 to align with the requirements of the Wyoming SIP extending the requirement to cease coal firing to no later than January 30, 2019. The EPA issued final approval of the Wyoming SIP, including the Naughton Unit 3 gas conversion, on March 21, 2019. PacifiCorp removed the unit from coal-fueled service on January 30, 2019 and completed the gas conversion in August 2020. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SCR, to be replaced with permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the four Jim Bridger units and submitted a regional haze SIP revision to the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) of the Clean Air Act, allowing the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took comment on the proposal through February 17, 2022. On February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp under Sections 201 and 209(a) of the Wyoming Environmental Quality Act, resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must convert both units to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4.
The state of Colorado regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2017 and 2019 IRPs.
Until the EPA takes final action in each state and decisions have been made in the pending appeals, PacifiCorp cannot fully determine the impacts of the Regional Haze Rule on its respective generating facilities.
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014 and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp and MidAmerican Energy are assessing the options for compliance at their generating facilities impacted by the final rule and will complete impingement and entrainment studies. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The costs of compliance with the cooling water intake structure rule cannot be fully determined until the prescribed studies are conducted and the respective state environmental agencies review the studies to determine whether additional mitigation technologies should be applied. If PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific do not utilize once-through cooling water intake or discharge structures at any of their generating facilities. All of the Nevada Power and Sierra Pacific generating stations are designed to have either minimal or zero discharge; therefore, they are not impacted by the §316(b) final rule.
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally promulgated guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal with the new limits to be met as soon as possible, beginning November 1, 2018 and fully implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review and requested the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018 and on September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. In a separate action, on April 12, 2019, the Fifth Circuit Court of Appeals vacated two aspects of the final effluent limitation guidelines, concerning discharge limits for (1) legacy wastewater from ash transport or treatment systems and (2) combustion residual leachate from landfills or settling ponds. The Fifth Circuit found that the EPA's own data did not support the agency's conclusion that impoundments were the best technology available for these two waste streams. The EPA must now complete a new effluent limitation guideline for these discharge limits. On November 22, 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule was finalized in October 2020 and took effect December 14, 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. The rule does not address the wastestreams at issue in the Fifth Circuit Court of Appeal's April 2019 decision. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025.
In April 2014, the EPA and the United States Army Corps of Engineers ("Corps of Engineers") issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but was appealed in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized September 12, 2019. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. On January 23, 2020, the EPA and the Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, which took effect 60 days after it was published in the Federal Register, redefines what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act is considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. On June 9, 2021, the EPA and the Corps of Engineers announced their intention to again revise the definition of "waters of the United States." After reviewing the Navigable Waters Protection Rule in accordance with Executive Order 13990, the agencies determined that the rule significantly reduced clean water protections. The agencies announced their intention to restore the clean water protections that were in place prior to the implementation of the "waters of the United States" rule in 2015. On August 30, 2021, the United States District Court for the District of Arizona vacated the Navigable Waters Protection Rule and the agencies quickly announced that they would no longer implement the rule nationwide. As a result, the agencies are relying on the pre-2015 regulatory definition of "waters of the United States" until they promulgate a new definition. Projects that are already permitted under the Navigable Waters Protection Rule and those that received an approved jurisdictional determination in reliance on the rule may continue to rely on those authorizations until they expire. Until the agencies take final action to update the definition of "waters of the United States," impacts to the relevant Registrants cannot be determined.
In April 2020, the United States Supreme Court established a new test for Clean Water Act jurisdiction in County of Maui, Hawaii v. Hawaii Wildlife Fund, finding that the statute can cover discharges of contaminated groundwater in certain circumstances. The United States Supreme Court outlined a seven-factor test to determine whether discharges conveyed through groundwater to surface water are "functionally equivalent" to direct discharges, finding that the time it takes for pollutants to travel through groundwater and the distance traveled are the two most important factors in the test. The United States Supreme Court remanded County of Maui, Hawaii to the Ninth Circuit Court of Appeals for further adjudication, which subsequently remanded the case to the district court to determine whether additional discovery is needed before applying the new seven-factor test. The EPA finalized guidance January 14, 2021, implementing County of Maui, Hawaii. The EPA utilized the United States Supreme Court's seven factors, plus an additional factor for the design and performance of the system or facility from which the pollutant is reached, to determine whether pollutants that reach surface waters after traveling through groundwater are a "functional equivalent" to a direct discharge that require a permit. Until the functional equivalent test and guidance are applied by the courts, the Registrants cannot determine the impact of this case on their operations.
In April 2020, the United States District Court of the District of Montana vacated nationwide permit 12, which provides an expedited route for projects like oil and gas pipelines and utility lines to achieve compliance with the Clean Water Act, finding that the Corps of Engineers, which implements the nationwide permit program, failed to conduct necessary programmatic consultation of nationwide permit 12 under the Endangered Species Act. The district court's vacatur, which was subsequently limited just to the Keystone XL pipeline project, the subject of the initial lawsuit, is on appeal to the Ninth Circuit Court of Appeals. On January 13, 2021, the Corps of Engineers finalized a rule modifying its nationwide permit program for certain activities affecting waters of the United States. The final rule restructures the nationwide permit program for utility lines by splitting the existing nationwide permit 12 into three separate nationwide permits – one for oil and gas, including pipelines; one for electrical and telecommunications; and one for water/sewer and other utilities. The Corps of Engineers included a biological assessment for the final rule but did not conduct a formal Endangered Species Act consultation in connection with reissuance of the nationwide permits. The Corps of Engineers reissued and revised 12 of 52 and added four new nationwide permits, which will be effective for a period of five years. The remaining nationwide permits are scheduled for renewal in advance of expiration in 2022. Until the nationwide permit challenges are fully litigated, the Registrants cannot determine the impact of this case on their operations.
Coal Combustion Byproduct Disposal
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the RCRA. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports was posted to the respective Registrant's coal combustion rule compliance data and information websites in March 2018. Based on the results in those reports, additional action may be required under the rule.
At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit on November 20, 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. On August 21, 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to the EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held the EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, on March 15, 2018, issued a proposal to address provisions of the final CCR rule that were remanded back to the agency on June 14, 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of CCR units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The EPA finalized the first phase of the CCR rule amendments on July 30, 2018, with an effective date of August 28, 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 proposal modifies the definition of "beneficial use" by replacing a mass-based threshold with new location-based criteria for triggering the need to conduct an environmental demonstration; establishes a definition of "CCR storage pile" to address the temporary storage of CCR on the ground, depending on whether the material is destined for disposal or beneficial use; makes certain changes to the rule's annual groundwater monitoring and corrective action reports to make it easier for the public to see and understand the data contained within the reports; modifies the requirements related to facilities' publicly available CCR rule websites to make the information more readily available; and establishes a risk-based groundwater monitoring protection standard for boron in the event the EPA decides to add boron to Appendix IV in the CCR rule. The EPA accepted comments on the Phase 2 proposal through October 15, 2019. On December 22, 2020, the EPA released a notice of data availability relating to the Phase 2 proposal to revise the CCR rule's definition of beneficial use and provisions governing piles of CCR on- and off-site prior to beneficial use. The new information presented by the notice includes data and information the EPA received during the comment period on the Phase 2 proposal. The EPA accepted comment on the notice of data availability through February 22, 2021. The EPA has not announced an anticipated timeline for completing the Phase 2 rule. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The proposal would require permits for all CCR units in states that do not have an EPA-approved CCR program. The proposal would establish individual, general and permit-by-rule permits; a tiered schedule for applications to prioritize permits for high-hazard potential CCR units; and postpone timelines for permit applications for all other CCR units. The EPA has not announced an anticipated timeline for completing the federal CCR permit rule. In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. Issues identified by the EPA include the definition of a legacy impoundment, information on the universe of legacy impoundments, the types of regulatory requirements that should apply to legacy impoundments, and the EPA's regulatory authority to regulate legacy impoundments under RCRA subtitle D. The EPA accepted comment on the advanced notice through February 12, 2021. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule was finalized in August 2020 and establishes a new deadline of April 11, 2021, by which all unlined surface impoundments (including clay lined impoundments that do not otherwise meet the definition of "lined") must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. In addition to these closure deadline provisions, the Part A rule also finalized changes to the CCR rule's annual groundwater monitoring and corrective action reports and modified requirements related to CCR rule compliance websites initially proposed in the Phase 2 rule. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton facility and ash pond and submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule. In December 2020, the EPA finalized its Holistic Approach to Closure: Part B rule ("Part B rule"), which establishes procedures for owners and operators of unlined ash ponds to demonstrate that the liner systems or underlying soils for these units perform as well as the liner criteria in the CCR rule. Additional provisions included in the proposed rule but not finalized, including the use of CCR in closure activities and allowing for the completion of groundwater corrective action during the post-closure care period, will be addressed in future rulemakings. As finalized, none of the relevant Registrants anticipate exercising the provisions of the Part B rule.
Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' CCR permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Using that guidance, the state of Oklahoma applied for EPA approval of its state program, and, on June 28, 2018, the EPA's approval of the application was published in the Federal Register. Environmental groups, including Waterkeeper Alliance and the Sierra Club, filed suit in the D.C. Circuit on September 26, 2018, alleging that the EPA unlawfully approved Oklahoma's permit program. This suit also incorporates claims first identified in a July 26, 2018 notice of intent to sue that alleged the EPA failed to perform nondiscretionary duties related to the development and publication of minimum guidelines for public participation in the approval of state permit programs for CCR. To date, none of the states in which the Registrants operate has applied for EPA approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required PacifiCorp to submit permit applications for two of its landfills by March 2017. It is anticipated that the state of Utah will apply for EPA approval of its CCR permit program prior to the end of 2021. In 2019, the state of Wyoming proposed to adopt state rules which incorporate the final federal rule by reference. It is anticipated that Wyoming will finalize its rule and seek the EPA's approval to implement a state permit program in 2021.
Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.
On January 20, 2021, President Biden issued an executive order on climate change which also required review of actions taken over the preceding four years that were harmful to "public health, environment, unsupported by the best available science, or otherwise not in the national best interest." The order included a non-exhaustive list of regulatory actions to be reviewed by the issuing agencies, including New Source Performance Standards for the power sector and the oil and gas sector, rescission of the Clean Power Plan, particulate matter and ozone NAAQS, steam electric effluent limitation guidelines, waters of the United States, reissuance of nationwide permits, and the phase one, part one and holistic approach to closure: parts A and B under the CCR rule. In addition, the Biden administration issued a regulatory freeze memorandum that prohibits submission of rules and guidance documents to the Federal Register without direct review, requires immediate withdrawal of rules and guidance documents submitted to the Federal Register but not yet published, and, for rules and guidance documents published but not yet having taken effect, consideration of a 60-day delay and possible additional comment period. Until the issuing agency completes its review and takes final action consistent with these directives, the relevant Registrant cannot determine whether additional action under any of these rules will be necessary.
Other
Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:
•The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Certain Registrants have been identified as potentially responsible parties in connection with certain disposal sites. The relevant Registrants have completed several cleanup actions and are participating in ongoing investigations and remedial actions. Costs associated with these actions are not expected to be material and are expected to be found prudent and included in rates.
•The Nuclear Waste Policy Act of 1982, under which the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 14 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 11 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.
•The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.
•The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding the relicensing of PacifiCorp's Klamath River hydroelectric system.
The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.
Item 1A. Risk Factors
Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.
Corporate and Financial Structure Risks
BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.
BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:
•their respective earnings, capital requirements, and required debt and preferred stock payments;
•the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and
•regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.
BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.
A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2021, BHE had the following outstanding obligations:
•senior unsecured debt of $13.0 billion;
•junior subordinated debentures of $100 million;
•guarantees and letters of credit in respect of subsidiaries, equity method investments and other related parties aggregating $1.4 billion; and
•commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $356 million.
BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $38.7 billion as of December 31, 2021. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.
Given BHE's substantial leverage, it may not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
The terms of BHE's and its subsidiaries' debt do not limit BHE's ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's or its subsidiaries' financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain
distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.
Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.
A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market could be significantly limited, resulting in higher interest costs.
Similarly, any downgrade or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity.
Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts could be material and could adversely affect such Registrant's liquidity and cash flows.
BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp'spreferred stockholders.
Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.
BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power and Sierra Pacific and the membership interest in Eastern Energy Gas. BHE is also the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.
Business Risks
Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.
Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.
An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize the anticipated benefits of the acquisition.
BHE cannot assure that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.
The Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems, which could adversely affect each respective Registrant's financial results.
The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on United States federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third-party excavation errors; unexpected degradation of pipeline systems; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, pandemics and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. The extent of that liability would be determined by the applicable state law where any such damage occurred. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources.
Further, the Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs or other damages. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured. Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's financial results.
The Registrants are subject to increasing risk from catastrophic wildfires and may be unable to obtain enough insurance coverage at a reasonable cost or at all to adequately protect the Registrants from liability, which could materially affect the Registrants financial results and liquidity.
The risk of catastrophic and severe wildfires has increased in the western United States giving rise to large damage claims against utilities for fire-related losses. Catastrophic and severe wildfires can occur in PacifiCorp, Nevada Power and Sierra Pacific's ("Western Domestic Utilities") service territory even when the Western Domestic Utilities effectively implement their wildfire mitigation plans and prudently manage their systems.
In California, for example, where PacifiCorp operates, "inverse condemnation" currently exposes utilities to potential liability for property damages where the utility's electrical equipment was a substantial cause of the wildfire. California courts have held that utilities can be held liable under inverse condemnation without being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover attorney's fees. As a result of inverse condemnation being applied to utilities and wildfire damages, recent losses recorded by insurance companies, and the risk of an increase in the frequency, duration and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in amounts necessary to cover potential losses. Uninsured losses and increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and may not be recoverable in customer rates.
The Western Domestic Utilities monitor weather conditions with specific thresholds for designated high fire consequence areas to help ensure the safe and reliable operation of their systems during periods of elevated wildfire ignition risk. Should weather conditions become extreme, the Western Domestic Utilities may de-energize certain sections of their distribution and transmission facilities as a last resort to minimize risk to the public. These "public safety power shutoffs" could be subject to increased scrutiny by regulators and policy makers. And, although "public safety power shutoffs" are intended to minimize risk of wildfire ignition, de-energization may cause other damages for which the Western Domestic Utilities could be held liable.
Damage claims against PacifiCorp for the 2020 Wildfires (as defined below) may materially affect PacifiCorp's financial condition and results of operations.
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California. Investigations into the cause and origin of each wildfire are complex and ongoing. Several lawsuits and complaints have been filed in Oregon and California associated with the wildfires, and it is possible that additional lawsuits and complaints against PacifiCorp may be filed. If PacifiCorp is found liable for damages related to the 2020 Wildfires and is unable to, or believes that it will be unable to, recover those damages through insurance or customer rates, or access the bank and capital markets on reasonable terms, PacifiCorp's financial results could be adversely affected. Refer to Item 3. Legal Proceedings, BHE's Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the 2020 Wildfires.
Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks.
Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services or otherwise reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local legislation related to such epidemics, pandemics or other outbreaks (or other similar laws, regulations, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related assessment of late fees, due to non-payment or other circumstances. Additionally, HomeServices' real estate businesses could experience a decline (which could be significant) in real estate transactions if potential customers elect to defer purchases in reaction to any epidemic, pandemic or other outbreak or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.
Further, epidemics, pandemics or other outbreaks could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of the Registrants' renewable generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.
Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.
Each Registrant is subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability, data privacy and other laws and regulations that affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including initiatives regarding deregulation and restructuring of the utility industry, are continually being proposed and enacted that impose new or revised requirements or standards on each Registrant.
Each Registrant is required to comply with numerous federal, state, local and foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring, disposing or retiring of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; managing and reporting transactions between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the United States, and foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.
Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's financial results.
Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenues within each Registrant's service territories; new environmental requirements, including the implementation of or changes to the Affordable Clean Energy rule, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.
New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:
•Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
•Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
•Additional costs may be incurred to purchase and deploy new generating technologies;
•Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
•Operating costs may be higher and generating unit outputs may be lower;
•Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and
•The relevant Registrant's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions, nor can each Registrant determine their impact on it at this time; however, any one of these could adversely affect each Registrant's financial results through higher capital expenditures and operating costs, early closure of generating facilities or lower tax benefits or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's financial results.
Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's financial results.
State Regulatory Rate Review Proceedings
The Utilities establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases or requesting rate decreases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.
States set retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are prudently incurred in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return or recover all of its costs even if it believes such costs to be prudently incurred.
Some state regulatory commissions have authorized recovery of certain costs above the level assumed in establishing base rates through adjustment mechanisms, which may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and adjustment mechanisms or through future general regulatory rate reviews. Any of these consequences could adversely affect each Registrant's financial results.
FERC Jurisdiction
The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity in the wholesale market, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.
The NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.
The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.
Rates for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's ratemaking principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline system's regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline system and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition, the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.
Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.
GEMA Jurisdiction
The Northern Powergrid Distribution Companies, as DNOs and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year-to-year but is a control on revenue that operates independent of a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license, it can appeal the matter to the United Kingdom's CMA. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.
AUC Jurisdiction
The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.
The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing. The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulations and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.
Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its financial results.
Each Registrant relies on technology in virtually all aspects of its business. Like those of many large businesses, certain of the Registrant's technology systems have been subject to computer viruses, malicious codes, unauthorized access, phishing efforts, denial-of-service attacks and other cyber attacks and each Registrant expects to be subject to similar attacks in the future as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by physical or cyber attack could result in-service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.
Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion at one or more of each Registrant's operations could adversely affect the impacted Registrant's financial results. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire, develop, implement, adopt or protect rights around new technology, it may suffer a competitive disadvantage.
Each Registrant is actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.
Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, and continued maintenance and upgrades of existing assets.
Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, and the imposition of tariffs thereon when sourced by foreign providers, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's financial results.
Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results. Factors that could lead to a decrease in market demand include, among others:
•a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;
•an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;
•shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including shale gas sources;
•efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and private generation measures and programs;
•laws mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;
•a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;
•a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and
•sustained mild weather that reduces heating or cooling needs.
Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.
In most parts of the United States and other markets in which each Registrant operates, demand for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, including the western portion of PacifiCorp's service territory, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered generating capacity, and BHE's unregulated subsidiaries are adding solar-powered and wind-powered generating capacity, each of which is also a climate-dependent resource.
As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its financial results. The extent of fluctuation in each Registrant's financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy and Nevada Power, and terms of its wholesale sale contracts.
Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its financial results.
In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have ECAMs, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors.
Potential terrorist activities and the impact of military or other actions, could adversely affect each Registrant's financial results.
The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the United States government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.
Certain Registrants are subject to the unique risks associated with nuclear generation.
The ownership and operation of nuclear generating facilities, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, compliance with and changes in regulation of nuclear generating facilities, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Constellation Energy, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the generating facility is significantly less than market wholesale prices. The following are among the more significant of these risks:
•Operational Risk - Operations at any nuclear generating facility could degrade to the point where the generating facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the generating facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the generating facility, the generating facility could be shut down. Furthermore, a shut-down or failure at any other nuclear generating facility could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expense of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear generating facilities, including Quad Cities Station, in the future.
•Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
•Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere, such as at the Fukushima Daiichi nuclear generating facility in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.
Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its financial results.
If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenues are generated under transportation, storage and LNG contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.
Each Registrant is subject to counterparty risk, which could adversely affect its financial results.
Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant continues to monitor the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if any Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on each Registrant's liquidity and its financial results.
Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.
Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its financial results.
The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with E.ON and British Gas Trading Limited accounting for approximately 23% and 12%, respectively, of distribution revenue in 2021. AltaLink's primary source of operating revenue is the AESO. Generally, a single customer purchases the energy from BHE's independent power projects in the United States pursuant to long-term power purchase agreements. For example, certain of BHE Renewables' solar and wind independent power projects sell all of their electrical production to either PG&E or SCE, respectively. Any material payment or other performance failure by the counterparties in these arrangements could have a significant adverse impact on BHE's consolidated financial results.
BHE owns investments in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.
BHE's business operations and investments outside the United States increase its risk related to fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, United States dollars or a currency freely convertible into United States dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.
In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, pandemics (including potentially in relation to COVID-19), expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.
Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows, liquidity and financial results.
Costs of providing each Registrant's defined benefit pension and other postretirement benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Furthermore, the timing of recognition of unrecognized gains and losses associated with the Registrants' defined benefit pension plans is subject to volatility due to events that may give rise to settlement accounting. Settlement events resulting from lump sum distributions offered by certain of the Registrants' defined benefit pension plans are influenced by the interest rates used to discount a participant's lump sum distribution. When the applicable interest rates are low, lump sum distributions in a given year tend to increase resulting in a higher likelihood of triggering settlement accounting.
If the Registrant's pension and other postretirement benefit plans are in underfunded positions, the respective Registrant may be required to make cash contributions to fund such underfunded plans in the future. Additionally, each Registrant's plans have investments in domestic and foreign equity and debt securities and other investments that are subject to loss. Losses from investments could add to the volatility, size and timing of future contributions.
Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation.
In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear generating facility, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. The funds that MidAmerican Energy has invested in a nuclear decommissioning trust and a subsidiary of PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp's subsidiary to make additional cash contributions. As contributions to the trust are being made over the operating life of the respective facility, reductions in the expected operating life of the facility could also require MidAmerican Energy and PacifiCorp's subsidiary to make additional contributions to the related trust. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash.
Inflation and changes in commodity prices and fuel transportation costs may adversely affect each Registrant's financial results.
Inflation and increases in commodity prices and fuel transportation costs may affect each Registrant by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures, each Registrant may not be able to pass the costs of inflation on to its customers. If each Registrant is unable to manage cost increases or pass them on to its customers, its financial results could be adversely affected.
Cyclical fluctuations and competition in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
•rising interest rates or unemployment rates, including a sustained high unemployment rate in the United States;
•periods of economic slowdown or recession in the markets served or the adverse effects on market actions as a result of epidemics, pandemics or other outbreaks;
•decreasing home affordability;
•lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;
•inadequate home inventory levels;
•sources of new competition; and
•changes in applicable tax law.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the United States, Great Britain, Canada and global credit markets, such as those that occurred in 2008, 2009 and 2020, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the United States or globally may adversely affect the United States' credit markets and could negatively impact each Registrant's ability to access funds on favorable terms or at all. If a Registrant is unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its financial results.
Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its financial results.
Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established liabilities or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct its business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on such Registrant's financial results.
Item 1B.Unresolved Staff Comments
Not applicable.
Item 2.Properties
Each Registrant's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, LNG facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 22 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K and Notes 4 and 5 of the Notes to Consolidated Financial Statements of Eastern Energy Gas in Item 8 of this Form 10-K.
The following table summarizes Berkshire Hathaway Energy's operating electric generating facilities as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Facility Net | | Net Owned |
Energy | | | | | | Capacity | | Capacity |
Source | | Entity | | Location by Significance | | (MWs) | | (MWs) |
| | | | | | | | |
Wind | | PacifiCorp, MidAmerican Energy and BHE Renewables | | Iowa, Wyoming, Texas, Nebraska, Washington, California, Illinois, Montana, Oregon and Kansas | | 11,517 | | | 11,517 | |
Natural gas | | PacifiCorp, MidAmerican Energy, NV Energy, BHE Renewables and BHE Canada | | Nevada, Utah, Iowa, Illinois, Washington, Wyoming, Oregon, Texas, New York, Arizona and Canada | | 11,112 | | | 10,833 | |
Coal | | PacifiCorp, MidAmerican Energy and NV Energy | | Wyoming, Iowa, Utah, Nevada, Colorado and Montana | | 13,235 | | | 8,193 | |
Solar | | BHE Renewables and NV Energy | | California, Texas, Arizona, Minnesota and Nevada | | 1,719 | | | 1,571 | |
Hydroelectric | | PacifiCorp, MidAmerican Energy and BHE Renewables | | Washington, Oregon, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming | | 1,149 | | | 1,149 | |
Nuclear | | MidAmerican Energy | | Illinois | | 1,823 | | | 456 | |
Geothermal | | PacifiCorp and BHE Renewables | | California and Utah | | 377 | | | 377 | |
| | | | Total | | 40,932 | | | 34,096 | |
Additionally, as of December 31, 2021, the Company has electric generating facilities that are under construction in Nevada, Iowa and Canada having total Facility Net Capacity and Net Owned Capacity of 421 MWs.
The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through prescription, eminent domain or similar rights. PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas and Kern River in the United States; Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc in Great Britain; and AltaLink in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the United States and Canadian utilities do not have the power of eminent domain with respect to governmental, Native American or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.
With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.
Item 3.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain, South Obenchain, Two Four Two and Santiam Canyon (also known as Beachie Creek) fires, as well as to add claims for noneconomic damages. The amended complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The amended complaint seeks the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595, Multnomah County, Oregon, in which two complaints, Case No. 21cv09339 and Case No. 21cv09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek Fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages.
Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part II, Item 8 of this Form 10-K, and PacifiCorp, refer to Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Part II, Item 8 of this Form 10-K.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.
PART II
Item 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
BERKSHIRE HATHAWAY ENERGY
BHE's common stock is beneficially owned by Berkshire Hathaway, family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, and Mr. Gregory E. Abel, BHE's Chair, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
PACIFICORP
All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE. PacifiCorp declared and paid dividends to PPW Holdings LLC of $150 million in 2021 and $— million in 2020.
MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY
All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. Neither MidAmerican Funding nor MidAmerican Energy declared or paid any cash distributions or dividends to its sole member or shareholder in 2021 and 2020.
NEVADA POWER
All common stock of Nevada Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Nevada Power declared and paid dividends to NV Energy of $213 million in 2021 and $155 million in 2020.
SIERRA PACIFIC
All common stock of Sierra Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Sierra Pacific declared and paid dividends to NV Energy of $— million in 2021 and $20 million in 2020.
EASTERN ENERGY GAS
Eastern Energy Gas is a Virginia limited liability corporation whose membership interest is held solely by its parent company, BHE GT&S, which is an indirect, wholly owned subsidiary of BHE. Eastern Energy Gas did not declare or pay cash distributions to BHE GT&S in 2021 or 2020. Eastern Energy Gas declared and paid cash distributions to DEI of $4.3 billion in 2020.
Item 6.[Reserved]
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
| | | | | | | | |
Berkshire Hathaway Energy Company and its subsidiaries | | |
PacifiCorp and its subsidiaries | | |
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company | | |
Nevada Power Company and its subsidiaries | | |
Sierra Pacific Power Company and its subsidiaries | | |
Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
| | | | | | | | |
Berkshire Hathaway Energy Company and its subsidiaries | | |
PacifiCorp and its subsidiaries | | |
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company | | |
Nevada Power Company and its subsidiaries | | |
Sierra Pacific Power Company and its subsidiaries | | |
Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
Item 8.Financial Statements and Supplementary Data
| | | | | | | | |
Berkshire Hathaway Energy Company and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Comprehensive Income | | |
Consolidated Statements of Changes in Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
PacifiCorp and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Comprehensive Income | | |
Consolidated Statements of Changes in Shareholders' Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
MidAmerican Energy Company | | |
Report of Independent Registered Public Accounting Firm | | |
Balance Sheets | | |
Statements of Operations | | |
| | |
Statements of Changes in Shareholder's Equity | | |
Statements of Cash Flows | | |
Notes to Financial Statements | | |
MidAmerican Funding, LLC and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
| | |
Consolidated Statements of Changes in Member's Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Nevada Power Company and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Changes in Shareholder's Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Sierra Pacific Power Company and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Changes in Shareholder's Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
Report of Independent Registered Public Accounting Firm | | |
Consolidated Balance Sheets | | |
Consolidated Statements of Operations | | |
Consolidated Statements of Comprehensive Income | | |
Consolidated Statements of Changes in Equity | | |
Consolidated Statements of Cash Flows | | |
Notes to Consolidated Financial Statements | | |
Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MES, corporate functions and intersegment eliminations.
Results of Operations
Overview
Operating revenue and earnings on common shares for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Operating revenue: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | | 5 | % |
MidAmerican Funding | 3,547 | | | 2,728 | | | 819 | | | 30 | | | 2,728 | | | 2,927 | | | (199) | | | (7) | |
NV Energy | 3,107 | | | 2,854 | | | 253 | | | 9 | | | 2,854 | | | 3,037 | | | (183) | | | (6) | |
Northern Powergrid | 1,188 | | | 1,022 | | | 166 | | | 16 | | | 1,022 | | | 1,013 | | | 9 | | | 1 | |
BHE Pipeline Group | 3,544 | | | 1,578 | | | 1,966 | | | * | | 1,578 | | | 1,131 | | | 447 | | | 40 | |
BHE Transmission | 731 | | | 659 | | | 72 | | | 11 | | | 659 | | | 707 | | | (48) | | | (7) | |
BHE Renewables | 981 | | | 936 | | | 45 | | | 5 | | | 936 | | | 932 | | | 4 | | | — | |
HomeServices | 6,215 | | | 5,396 | | | 819 | | | 15 | | | 5,396 | | | 4,473 | | | 923 | | | 21 | |
BHE and Other | 541 | | | 438 | | | 103 | | | 24 | | | 438 | | | 556 | | | (118) | | | (21) | |
Total operating revenue | $ | 25,150 | | | $ | 20,952 | | | $ | 4,198 | | | 20 | % | | $ | 20,952 | | | $ | 19,844 | | | $ | 1,108 | | | 6 | % |
| | | | | | | | | | | | | | | |
Earnings on common shares: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 889 | | | $ | 741 | | | $ | 148 | | | 20 | % | | $ | 741 | | | $ | 773 | | | $ | (32) | | | (4) | % |
MidAmerican Funding | 883 | | | 818 | | | 65 | | | 8 | | | 818 | | | 781 | | | 37 | | | 5 | |
NV Energy | 439 | | | 410 | | | 29 | | | 7 | | | 410 | | | 365 | | | 45 | | | 12 | |
Northern Powergrid | 247 | | | 201 | | | 46 | | | 23 | | | 201 | | | 256 | | | (55) | | | (21) | |
BHE Pipeline Group | 807 | | | 528 | | | 279 | | | 53 | | | 528 | | | 422 | | | 106 | | | 25 | |
BHE Transmission | 247 | | | 231 | | | 16 | | | 7 | | | 231 | | | 229 | | | 2 | | | 1 | |
BHE Renewables(1) | 451 | | | 521 | | | (70) | | | (13) | | | 521 | | | 431 | | | 90 | | | 21 | |
HomeServices | 387 | | | 375 | | | 12 | | | 3 | | 375 | | | 160 | | | 215 | | | * |
BHE and Other | 1,319 | | | 3,092 | | | (1,773) | | | (57) | | | 3,092 | | | (467) | | | 3,559 | | | * |
Total earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | (1,248) | | | (18) | % | | $ | 6,917 | | | $ | 2,950 | | | $ | 3,967 | | | * |
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful.
Earnings on common shares decreased $1,248 million for 2021 compared to 2020. Included in these results was a pre-tax unrealized gain in 2021 of $1,796 million ($1,777 million after-tax) compared to a pre-tax unrealized gain in 2020 of $4,774 million ($3,470 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares in 2021 was $3,892 million, an increase of $445 million, or 13%, compared to adjusted earnings on common shares in 2020 of $3,447 million.
The decrease in net income attributable to BHE shareholders for 2021 compared to 2020 was primarily due to:
•The Utilities' earnings increased $242 million reflecting higher electric utility margin, favorable income tax expense, from higher PTCs recognized of $139 million and the impacts of ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense. Electric retail customer volumes increased 3.8% for 2021 compared to 2020, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather;
•Northern Powergrid's earnings increased $46 million, primarily due to higher distribution performance, lower write-offs of gas exploration costs and $16 million from the weaker United States dollar, partially offset by the comparative unfavorable impact of deferred income tax charges ($109 million in second quarter 2021 and $35 million in third quarter 2020) related to enacted increases in the United Kingdom corporate income tax rate;
•BHE Pipeline Group's earnings increased $279 million, primarily due to $244 million of incremental earnings at BHE GT&S;
•BHE Renewables' earnings decreased $70 million, primarily due to lower tax equity investment earnings from the February 2021 polar vortex weather event, partially offset by earnings from tax equity investment projects reaching commercial operation and higher operating performance from owned renewable energy projects; and
•BHE and Other's earnings decreased $1,773 million, primarily due to the $1,693 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited and $95 million of higher dividends on BHE's 4.00% Perpetual Preferred Stock issued in October 2020, partially offset by favorable comparative consolidated state income tax benefits.
Earnings on common shares increased $3,967 million for 2020 compared to 2019. Included in these results was a pre-tax unrealized gain in 2020 of $4,774 million ($3,470 million after-tax) compared to a pre-tax unrealized loss in 2019 of $313 million ($227 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares in 2020 was $3,447 million, an increase of $270 million, or 9%, compared to adjusted earnings on common shares in 2019 of $3,177 million.
The increase in earnings on common shares for 2020 compared to 2019 was primarily due to:
•The Utilities' earnings increased $50 million with favorable performance at all four utilities (electric retail customer volumes increased 0.1%), including $193 million of higher PTCs recognized, offset by a comparative increase in wildfire and other storm restoration costs, primarily at PacifiCorp;
•Northern Powergrid's earnings decreased $55 million, mainly due to a deferred income tax charge in 2020 from an enacted increase in the United Kingdom corporate income tax rate;
•BHE Pipeline Group's earnings increased $106 million, primarily due to $73 million of incremental earnings at BHE GT&S and a favorable rate case settlement at Northern Natural Gas;
•BHE Renewables' earnings increased $90 million, primarily due to increased income tax benefits from renewable wind tax equity investments, largely from projects reaching commercial operation, offset by lower earnings from geothermal and natural gas facilities;
•HomeServices' earnings increased $215 million, primarily due to higher earnings from mortgage services (71% increase in funded mortgage volume) and brokerage services (13% increase in closed transaction volume) largely attributable to the favorable interest rate environment; and
•BHE and Other's earnings increased $3,559 million, primarily due to the $3,697 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited offset by higher BHE corporate interest expense and unfavorable comparative consolidated state income tax benefits.
Reportable Segment Results
PacifiCorp
Operating revenue decreased $45 million for 2021 compared to 2020, primarily due to lower retail revenue of $98 million, partially offset by higher wholesale and other revenue of $53 million. Retail revenue decreased mainly due to $234 million from the Utah and Oregon general rate case orders issued in 2020 (fully offset in expense, primarily depreciation) and price impacts of $41 million from lower rates primarily due to certain general rate case orders, partially offset by higher customer volumes of $177 million. Retail customer volumes increased 3.1%, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather. Wholesale and other revenue increased mainly due to higher wheeling revenue, average wholesale prices and REC sales, partially offset by $34 million from the Oregon RAC settlement (fully offset in depreciation expense) recognized in 2020.
Earnings increased $148 million for 2021 compared to 2020, primarily due to favorable income tax expense from higher PTCs recognized of $75 million from new wind-powered generating facilities placed in-service, and the impacts of ratemaking, lower operations and maintenance expense of $178 million and higher utility margin of $145 million, partially offset by higher depreciation and amortization expense of $255 million and lower allowances for equity and borrowed funds used during construction of $72 million. Operations and maintenance expense decreased primarily due to lower costs associated with wildfires and the Klamath Hydroelectric Settlement Agreement and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. Utility margin increased primarily due to the higher retail customer volumes, higher wheeling and wholesale revenue and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power and thermal generation costs, the price impacts from lower retail rates and higher wheeling expenses. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.
Operating revenue increased $273 million for 2020 compared to 2019, primarily due to higher retail revenue of $250 million and higher wholesale and other revenue of $23 million. Retail revenue increased primarily due to $234 million from the amortization of certain existing regulatory balances to offset the accelerated depreciation of certain property, plant and equipment and the accelerated amortization of certain regulatory asset balances in relation to Utah and Oregon general rate case orders issued in December 2020. The increase in retail revenue was also due to price impacts of $49 million from changes in sales mix, partially offset by lower customer volumes of $34 million. The increase in wholesale and other revenue was mainly due to $34 million from the amortization of certain existing regulatory balances in Oregon to offset the accelerated depreciation of certain retired wind equipment, partially offset by lower wholesale volumes. Retail customer volumes decreased 1.4% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of residential and commercial customers and the favorable impact of weather.
Earnings decreased $32 million for 2020 compared to 2019, primarily due to an increase in operations and maintenance expense due to higher costs associated with wildfires and the Klamath Hydroelectric Settlement Agreement of $169 million, higher interest expense of $25 million from higher long-term debt balances, higher pension and other postretirement costs of $13 million, lower interest income from lower average interest rates and higher property taxes of $10 million, partially offset by lower tax expense from higher PTCs recognized of $62 million from repowered and new wind-powered generating facilities, higher utility margin of $47 million and higher allowances for equity and borrowed funds used during construction of $38 million. Utility margin increased primarily due to lower coal-fueled and natural gas-fueled generation costs, lower purchased power costs and price impacts from changes in sales mix, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms and lower retail customer volumes.
MidAmerican Funding
Operating revenue increased $819 million for 2021 compared to 2020, primarily due to higher natural gas operating revenue of $430 million and higher electric operating revenue of $390 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $440 million (fully offset in cost of sales), largely due to the February 2021 polar vortex weather event. Electric operating revenue increased due to higher retail revenue of $198 million and higher wholesale and other revenue of $192 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $116 million (fully offset in expense, primarily cost of sales), higher customer volumes of $63 million and price impacts of $19 million from changes in sales mix. Electric retail customer volumes increased 5.8% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased primarily due to higher average wholesale prices of $116 million and higher wholesale volumes of $71 million.
Earnings increased $65 million for 2021 compared to 2020, primarily due to higher electric utility margin of $190 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $198 million, higher operations and maintenance expense of $20 million and lower allowances for equity and borrowed funds of $8 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. The favorable income tax benefit was largely due to higher PTCs recognized of $64 million, from new wind-powered generating facilities placed in-service, partially offset by state income tax impacts. The increase in depreciation and amortization expense was primarily due to the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service and higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities.
Operating revenue decreased $199 million for 2020 compared to 2019, primarily due to lower natural gas operating revenue of $77 million, lower electric operating revenue of $70 million, lower electric and natural gas energy efficiency program revenue of $38 million (fully offset in operations and maintenance expense) and lower other revenue of $14 million, primarily from nonregulated utility construction services. Natural gas operating revenue decreased primarily due to lower volumes and a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $68 million (fully offset in cost of sales) and a 10.2% decrease in retail customer volumes, primarily due to the unfavorable impact of weather. Electric operating revenue decreased due to lower wholesale and other revenue of $88 million, partially offset by higher retail revenue of $18 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale prices of $115 million, partially offset by higher wholesale volumes of $28 million. Electric retail revenue increased primarily due to higher customer usage of $38 million, partially offset by price impacts of $18 million from changes in sales mix. Electric retail customer volumes increased 1.2% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage.
Earnings increased $37 million for 2020 compared to 2019, primarily due to higher income tax benefit of $197 million from higher PTCs recognized of $132 million and the favorable impacts of ratemaking, partially offset by higher depreciation and amortization expense of $77 million due to additional assets placed in-service (offset by $23 million of lower Iowa revenue sharing accruals), lower allowances for equity and borrowed funds used during construction of $45 million, higher interest expense of $20 million and lower electric and natural gas utility margins. PTCs recognized increased due to higher wind-powered generation driven primarily by repowering and new wind projects placed in-service. Electric utility margin decreased due to lower wholesale revenue and the price impacts from changes in sales mix, partially offset by lower generation costs from higher wind generation and higher retail customer volumes. Natural gas utility margin decreased primarily due to lower retail customer volumes primarily due to the unfavorable impact of weather.
NV Energy
Operating revenue increased $253 million for 2021 compared to 2020, primarily due to higher electric operating revenue of $252 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $229 million, a $120 million one-time bill credit in the fourth quarter of 2020 resulting from a regulatory rate review decision (fully offset in operations and maintenance and income tax expenses) and higher retail customer volumes of $10 million, partially offset by lower base tariff general rates of $71 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 3.3%, primarily due to an increase in the average number of customers, higher customer usage and the favorable impact of weather.
Earnings increased $29 million for 2021 compared to 2020, primarily due to lower operations and maintenance expense of $90 million, lower income tax expense mainly from the impacts of ratemaking, lower interest expense of $21 million, higher interest and dividend income of $16 million and lower pension expense of $10 million, partially offset by lower electric utility margin of $97 million and higher depreciation and amortization expense of $47 million. Operations and maintenance expense decreased primarily due to lower regulatory deferrals and amortizations and lower earnings sharing at the Nevada Utilities. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by higher retail customer volumes. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.
Operating revenue decreased $183 million for 2020 compared to 2019, primarily due to lower electric operating revenue. Electric operating revenue decreased primarily due to lower fully-bundled energy rates (fully offset in cost of sales) of $164 million and a $120 million one-time bill credit in the fourth quarter of 2020 resulting from a regulatory rate review decision (fully offset in operations and maintenance and income tax expenses), partially offset by higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision. Electric retail customer volumes, including distribution only service customers, increased 1.5%, primarily due to the favorable impact of weather, largely offset by the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage.
Earnings increased $45 million for 2020 compared to 2019, primarily due to higher electric utility margin of $100 million, lower pension and post-retirement costs of $9 million and lower income tax expense mainly from the favorable impacts of ratemaking, partially offset by an increase in operations and maintenance expense, mainly from higher earnings sharing accruals at the Nevada Utilities, and higher depreciation and amortization expense of $20 million, mainly from higher plant placed in-service. Electric utility margin increased primarily due to higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision.
Northern Powergrid
Operating revenue increased $166 million for 2021 compared to 2020, primarily due to higher distribution revenue of $80 million, mainly from increased tariff rates of $40 million and a 3.2% increase in units distributed totaling $26 million, and $77 million from the weaker United States dollar.
Earnings increased $46 million for 2021 compared to 2020, primarily due to the higher distribution revenue, lower write-offs of gas exploration costs of $36 million, $16 million from the weaker United States dollar, favorable pension expense of $14 million and lower interest expense of $8 million, partially offset by higher income tax expense and higher distribution-related operating and depreciation expenses of $29 million. Earnings in 2021 included a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, while earnings in 2020 included a deferred income tax charge of $35 million related to a July 2020 enacted increase in the United Kingdom corporate income tax rate from 17% to 19% effective April 1, 2020.
Operating revenue increased $9 million for 2020 compared to 2019, primarily due to higher distribution revenue of $10 million from increased tariff rates of $40 million, partially offset by a 5.4% decrease in units distributed totaling $30 million largely due to the impacts of COVID-19.
Earnings decreased $55 million for 2020 compared to 2019, primarily due to write-offs of gas exploration costs of $44 million, higher income tax expense of $37 million and higher distribution-related operating and depreciation expenses of $18 million, partially offset by higher distribution revenue, lower pension expense of $22 million, including lower pension settlement losses recognized in 2020 compared to 2019, and lower interest expense of $9 million. The increase in income tax expense is due to a change in the United Kingdom corporate income tax rate that resulted in a deferred income tax charge of $35 million.
BHE Pipeline Group
Operating revenue increased $1,966 million for 2021 compared to 2020, primarily due to $1,828 million of incremental revenue at BHE GT&S, acquired in November 2020, higher gas sales of $115 million ($38 million largely offset in costs of sales) at Northern Natural Gas and higher transportation revenue of $29 million at Kern River largely due to higher rates and volumes, partially offset by lower transportation revenue of $24 million at Northern Natural Gas primarily due to lower volumes. The variances in gas sales and transportation revenue at Northern Natural Gas included favorable impacts of $77 million and $49 million, respectively, from the February 2021 polar vortex weather event.
Earnings increased $279 million for 2021 compared to 2020, primarily due to $244 million of incremental earnings at BHE GT&S, favorable earnings of $19 million at Kern River from the higher transportation revenue and higher earnings of $15 million at Northern Natural Gas, primarily due to higher gross margin on gas sales and higher transportation revenue, each due to the favorable impacts of the February 2021 polar vortex weather event, offset by the lower transportation revenue.
Operating revenue increased $447 million for 2020 compared to 2019, primarily due to $331 million of incremental revenue at BHE GT&S, a favorable rate case settlement at Northern Natural Gas of $101 million and higher transportation revenue of $43 million, partially offset by lower gas sales at Northern Natural Gas of $23 million related to system balancing activities (largely offset in cost of sales).
Earnings increased $106 million for 2020 compared to 2019, primarily due to $73 million of incremental earnings BHE GT&S, the higher transportation revenue, and a favorable after-tax, rate case settlement at Northern Natural Gas of $32 million, partially offset by higher property and other tax expense of $17 million, including a non-recurring property tax refund in 2019, higher depreciation and amortization expense of $13 million due to increased spending on capital projects and lower interest income of $9 million.
BHE Transmission
Operating revenue increased $72 million for 2021 compared to 2020, primarily due to $47 million from the stronger United States dollar, a regulatory decision received in November 2020 at AltaLink and higher revenue from the Montana-Alberta Tie Line of $11 million.
Earnings increased $16 million for 2021 compared to 2020, primarily due to $12 million from the stronger United States dollar, higher earnings from the Montana-Alberta Tie Line and lower non-regulated interest expense at BHE Canada, partially offset by the impact of a regulatory decision received in April 2020 at AltaLink.
Operating revenue decreased $48 million for 2020 compared to 2019, primarily due to a regulatory decision received in November 2020 at AltaLink and the stronger United States dollar of $7 million.
Earnings increased $2 million for 2020 compared to 2019, primarily due to lower non-regulated interest expense at BHE Canada and higher net income at BHE U.S. Transmission of $6 million mainly due to improved equity earnings from ETT, partially offset by the impacts of regulatory decisions received in 2020 and 2019 at AltaLink.
BHE Renewables
Operating revenue increased $45 million for 2021 compared to 2020, primarily due to higher natural gas, solar, wind and hydro revenues from favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $30 million.
Earnings decreased $70 million for 2021 compared to 2020, primarily due to lower wind earnings of $83 million, largely from lower tax equity investment earnings of $90 million, and lower hydro earnings of $10 million, mainly due to lower income from a declining financial asset balance, partially offset by higher solar earnings of $22 million, mainly due to the higher operating revenue and lower depreciation expense. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $165 million, primarily due to the February 2021 polar vortex weather event, and lower commitment fee income, partially offset by $87 million of earnings from projects reaching commercial operation.
Operating revenue increased $4 million for 2020 compared to 2019, primarily due to higher natural gas, solar and hydro revenues of $21 million due to favorable generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $14 million and lower geothermal revenues of $4 million from lower pricing.
Earnings increased $90 million for 2020 compared to 2019, primarily due to favorable wind tax equity investment earnings of $129 million, partially offset by lower geothermal earnings of $22 million, due to higher operations and maintenance expense and lower pricing, and lower natural gas earnings of $17 million, due to lower margins. Wind tax equity investment earnings improved due to $147 million of earnings from projects reaching commercial operation, partially offset by lower commitment fee income and lower earnings from existing tax equity investments of $6 million.
HomeServices
Operating revenue increased $819 million for 2021 compared to 2020, primarily due to higher brokerage revenue of $951 million, partially offset by lower mortgage revenue of $169 million from an 8% decrease in funded volume due to a decrease in refinance activity. The increase in brokerage revenue was due to a 21% increase in closed transaction volume at existing companies resulting from increases in average sales price and closed units.
Earnings increased $12 million for 2021 compared to 2020, primarily due to higher earnings from brokerage and franchise services of $81 million, largely attributable to the increase in closed transaction volume at existing companies, partially offset by lower earnings from mortgage services of $68 million from the decrease in refinance activity.
Operating revenue increased $923 million for 2020 compared to 2019, primarily due to higher brokerage revenue of $440 million from a 13% increase in closed transaction volume and higher mortgage revenue of $423 million from a 71% increase in funded mortgage volume due to an increase in refinance activity.
Earnings increased $215 million for 2020 compared to 2019, primarily due to higher earnings at mortgage services of $138 million and higher earnings at brokerage services largely attributable to the favorable interest rate environment.
BHE and Other
Operating revenue increased $103 million for 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MES, from favorable pricing offset by lower volumes.
Earnings decreased $1,773 million for 2021 compared to 2020, primarily due to the $1,693 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $95 million of higher dividends on BHE's 4.00% Perpetual Preferred Stock issued in October 2020, higher corporate costs and higher BHE corporate interest expense from debt issuances in March and October 2020, partially offset by favorable comparative consolidated state income tax benefits and higher earnings of $17 million at MES.
Operating revenue decreased $118 million for 2020 compared to 2019, primarily due to lower electricity and natural gas sales revenue at MES, from lower volumes.
Earnings increased $3,559 million for 2020 compared to 2019, primarily due to the $3,697 million change in the after-tax unrealized position of the Company's investment in BYD Company Limited, partially offset by higher BHE corporate interest expense from debt issuances in March and October 2020 and unfavorable comparative consolidated state income tax benefits.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of December 31, 2021, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | BHE | | |
| | | | | | | | | | | | | Pipeline Group, | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | HomeServices | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | and Other | | Total |
| | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 18 | | | $ | 179 | | | $ | 233 | | | $ | 42 | | | $ | 39 | | | $ | 75 | | | $ | 510 | | | $ | 1,096 | |
| | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 271 | | | 851 | | | 3,300 | | | 11,281 | |
Less: | | | | | | | | | | | | | | | |
Short-term debt | — | | | — | | | — | | | (339) | | | (1) | | | (245) | | | (1,424) | | | (2,009) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | (589) | |
Net credit facilities | 3,500 | | | 982 | | | 1,139 | | | 311 | | | 270 | | | 605 | | | 1,876 | | | 8,683 | |
| | | | | | | | | | | | | | | |
Total net liquidity | $ | 3,518 | | | $ | 1,161 | | | $ | 1,372 | | | $ | 353 | | | $ | 309 | | | $ | 680 | | | $ | 2,386 | | | $ | 9,779 | |
Credit facilities: | | | | | | | | | | | | | | | |
Maturity dates | 2024 | | 2024 | | 2022, 2024 | | 2024 | | 2024 | | 2022, 2026 | | 2022, 2026 | | |
| | | | | | | | | | | | | | | |
(1) Includes drawn uncommitted credit facilities totaling $1 million at Northern Powergrid.
Refer to Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $8.7 billion and $6.2 billion, respectively. The increase was primarily due to $970 million of incremental net cash flows from operating activities at BHE GT&S, improved operating results and changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $6,224 million and $6,206 million, respectively. The increase was primarily due to an increase in income tax receipts and improved operating results, partially offset by changes in working capital.
The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(5.8) billion and $(13.2) billion, respectively. The change was primarily due to lower funding of tax equity investments, lower cash paid for acquisitions and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $(13.2) billion and $(9.0) billion, respectively. The change was primarily due to higher cash paid for acquisitions and higher funding of tax equity investments, partially offset by lower capital expenditures of $599 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Natural Gas Transmission and Storage Business Acquisition
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Questar, exclusive of the Questar Pipeline Group (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments.
On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion to Dominion Questar on November 2, 2020.
On July 9, 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. On July 14, 2021, BHE received the Purchase Price Repayment Amount of approximately $1.3 billion in cash.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2021 were $(3.1) billion. Sources of cash totaled $2.4 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $5.5 billion and consisted mainly of preferred stock redemptions totaling $2.1 billion, repayments of subsidiary debt totaling $2.0 billion, distributions to noncontrolling interests of $488 million, repayments of BHE senior debt totaling $450 million and net repayments of short-term debt totaling $276 million.
Net cash flows from financing activities for the year ended December 31, 2020 were $7.1 billion. Sources of cash totaled $11.7 billion and consisted of proceeds from BHE senior debt issuances of $5.2 billion, proceeds from preferred stock issuances of $3.8 billion and proceeds from subsidiary debt issuances totaling $2.7 billion. Uses of cash totaled $4.5 billion and consisted mainly of $2.8 billion for repayments of subsidiary debt, net repayments of short-term debt of $939 million and $350 million for repayments of BHE senior debt.
Net cash flows from financing activities for the year ended December 31, 2019 were $3.1 billion. Sources of cash totaled $5.4 billion and consisted of proceeds from subsidiary debt issuances totaling $4.7 billion and net proceeds from short-term debt of $684 million. Uses of cash totaled $2.3 billion and consisted mainly of $1.9 billion for repayments of subsidiary debt and repurchases of common stock of $293 million.
Debt Repurchases
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Preferred Stock Issuance
On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration.
Preferred Stock Redemptions
For the year ended December 31, 2021, BHE redeemed at par 2,100,012 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $2.1 billion.
Common Stock Transactions
For the years ended December 31, 2020 and 2019, BHE repurchased 180,358 shares of its common stock for $126 million and 447,712 shares of its common stock for $293 million, respectively.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
PacifiCorp | $ | 2,175 | | | $ | 2,540 | | | $ | 1,513 | | | $ | 2,001 | | | $ | 3,317 | | | $ | 2,501 | |
MidAmerican Funding | 2,810 | | | 1,836 | | | 1,912 | | | 1,913 | | | 2,650 | | | 2,311 | |
NV Energy | 657 | | | 675 | | | 749 | | | 1,480 | | | 1,839 | | | 2,087 | |
Northern Powergrid | 602 | | | 682 | | | 742 | | | 677 | | | 633 | | | 632 | |
BHE Pipeline Group | 687 | | | 659 | | | 1,128 | | | 1,064 | | | 987 | | | 981 | |
BHE Transmission | 247 | | | 372 | | | 279 | | | 220 | | | 226 | | | 309 | |
BHE Renewables | 122 | | | 95 | | | 225 | | | 109 | | | 371 | | | 198 | |
HomeServices | 54 | | | 36 | | | 42 | | | 62 | | | 41 | | | 40 | |
BHE and Other(1) | 10 | | | (130) | | | 21 | | | 24 | | | 3 | | | 4 | |
Total | $ | 7,364 | | | $ | 6,765 | | | $ | 6,611 | | | $ | 7,550 | | | $ | 10,067 | | | $ | 9,063 | |
(1)BHE and Other includes intersegment eliminations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Wind generation | $ | 2,828 | | | $ | 2,125 | | | $ | 1,339 | | | $ | 1,010 | | | $ | 2,590 | | | $ | 2,283 | |
Electric distribution | 1,537 | | | 1,719 | | | 1,694 | | | 1,696 | | | 1,723 | | | 1,556 | |
Electric transmission | 1,070 | | | 958 | | | 813 | | | 1,624 | | | 2,380 | | | 1,985 | |
Natural gas transmission and storage | 717 | | 640 | | 1,068 | | | 908 | | | 882 | | | 879 | |
Solar generation | 5 | | 16 | | 157 | | | 189 | | | 760 | | | 949 | |
Other | 1,207 | | | 1,307 | | | 1,540 | | | 2,123 | | | 1,732 | | | 1,411 | |
Total | $ | 7,364 | | | $ | 6,765 | | | $ | 6,611 | | | $ | 7,550 | | | $ | 10,067 | | | $ | 9,063 | |
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $540 million for 2021, $848 million for 2020 and $1,486 million for 2019. MidAmerican Energy placed in-service 294 MWs during 2021, 729 MWs during 2020, including the acquisition of an existing 80-MW wind farm and 1,019 MWs during 2019. All of these wind-powered generating facilities placed in-service in 2021, 2020 and 2019 qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa EAC until these generation assets are reflected in base rates. Planned spending for the construction of wind-powered generating facilities totals $190 million in 2022, $1,744 million in 2023 and $1,678 million in 2024.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $354 million for 2021, $37 million for 2020 and $369 million for 2019. Planned spending for repowering totals $509 million in 2022. MidAmerican Energy expects its repowered facilities to meet IRS guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 865 MWs of current repowering projects not in-service as of December 31, 2021, 564 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $107 million for 2021, $1,148 million for 2020 and $338 million for 2019. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $131 million in 2022, $405 million in 2023 and $373 million in 2024. The energy production from the new wind-powered generating facilities placed in-service by the end of 2024 is expected to qualify for 60% of the federal PTCs available for 10 years once the equipment is placed in-service.
◦Repowering of existing wind-powered generating facilities at PacifiCorp totaling $9 million for 2021, $125 million for 2020 and $585 million for 2019. All existing wind-powered generating facilities at PacifiCorp have been repowered as of December 31, 2021.
◦The 2021 IRP also included PacifiCorp's planned acquisition and repowering of two wind-powered generating facilities. The repowered facilities are expected to be placed in-service in 2023 and 2024. PacifiCorp spent $11 million in 2021 and planned spending for acquiring and repowering generating facilities totals $60 million in 2022, $36 million in 2023 and $34 million in 2024.
◦Construction of wind-powered generating facilities at BHE Renewables totaling $155 million for 2021 and $15 million for 2019. In May 2021, BHE Renewables completed the asset acquisition of a 54-MW wind-powered generating facility located in Iowa. In December 2021, BHE Renewables completed asset acquisitions of 158-MW and 200-MW wind-powered generating facilities located in Texas. Planned spending for future wind generation totals $306 million in 2023 and $102 million in 2024.
•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦PacifiCorp's transmission investment in 2021 through 2024 primarily reflecting planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. PacifiCorp is advancing permitting and regulatory approvals related to the projects. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $565 million in 2022, $1,143 million in 2023 and $437 million in 2024.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Planned spending for the expansion programs estimated to be placed in-service in 2026-2028 totals $61 million in 2022, $148 million in 2023 and $498 million in 2024.
◦Operating expenditures include spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for asset modernization, pipeline integrity projects and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, with total spend of $132 million in 2021 and planned spending of $93 million in 2022 and $58 million in 2023.
◦Construction of solar-powered generating facilities at the Nevada Utilities' includes expenditures for three solar photovoltaic facilities, including a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada, with commercial operation expected by the end of 2023; a 250 MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada, with commercial operation expected by the end of 2023; and a 350 MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada, with commercial operation expected by the end of 2024. The facilities located in Humboldt County will be jointly owned and operated by Nevada Power and Sierra Pacific. Planned spending totals $702 million in 2023 and $799 million in 2024.
◦Construction of solar-powered generating facilities at BHE Renewables' includes expenditures for a 48-MW solar photovoltaic facility with an additional 52 MWs of capacity of co-located battery storage in Kern County, California, with commercial operation expected by November 30, 2024. Planned spending totals $150 million in 2024.
•Other capital expenditures includes both growth and operating expenditures, including spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of CCR.
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits.
As of December 31, 2021, the Company's investments that are accounted for under the equity method had short- and long-term debt of $2.7 billion, unused revolving credit facilities of $200 million and letters of credit outstanding of $88 million. As of December 31, 2021, the Company's pro-rata share of such short- and long-term debt was $1.3 billion, unused revolving credit facilities was $100 million and outstanding letters of credit was $43 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.
Material Cash Requirements
The Company has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Note 9, 10 and 11), operating and financing leases (refer to Note 6), firm commitments (refer to Note 16), letters of credit (refer to Note 9), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 12) and AROs (refer to Note 14). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The Company has cash requirements relating to interest payments of $32.4 billion on long-term debt, including $2.1 billion due in 2022.
Additionally, the Company has invested in wind projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $— million, $2,736 million and $1,619 million in 2021, 2020 and 2019, respectively, and has commitments as of December 31, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $356 million in 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
Regulatory Matters
The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding the Company's general regulatory framework and current regulatory matters.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1, 2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of BHE and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
BHE and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, the applicable entities' credit ratings from the recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, the Company would have been required to post $460 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the United States and Canada, the Regulated Businesses operate under cost-of-service based rate structures administered by various state and provincial commissions and the FERC. Under these rate structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
The Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $4.0 billion and total regulatory liabilities were $7.2 billion as of December 31, 2021. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Regulated Businesses' regulatory assets and liabilities.
Impairment of Goodwill and Long-Lived Assets
The Company's Consolidated Balance Sheet as of December 31, 2021 includes goodwill of acquired businesses of $11.7 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2021. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings or rate base; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors.
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.
Pension and Other Postretirement Benefits
Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2021, the Company recognized a net asset totaling $433 million for the funded status of the defined benefit pension and other postretirement benefit plans. As of December 31, 2021, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled $297 million and in AOCI totaled $428 million.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2021.
The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2025, at which point the rate of increase is assumed to remain constant.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Domestic Plans | | |
| | | | | Other Postretirement | | United Kingdom |
| Pension Plans | | Benefit Plans | | Pension Plan |
| +0.5% | | -0.5% | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | | | | | |
Effect on December 31, 2021 | | | | | | | | | | | |
Benefit Obligations: | | | | | | | | | | | |
Discount rate | $ | (136) | | | $ | 153 | | | $ | (33) | | | $ | 37 | | | $ | (162) | | | $ | 189 | |
| | | | | | | | | | | |
Effect on 2021 Periodic Cost: | | | | | | | | | | | |
Discount rate | $ | — | | | $ | 5 | | | $ | 1 | | | $ | — | | | $ | (20) | | | $ | 23 | |
Expected rate of return on plan assets | (13) | | | 13 | | | (4) | | | 4 | | | (12) | | | 12 | |
A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and the Company's funding policy for each plan.
Income Taxes
In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.
It is probable the Company's regulated businesses will continue to pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $2.8 billion and will be included in regulated rates when the temporary differences reverse.
The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely; however, the Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of the Company's undistributed foreign earnings were repatriated, the dividends may be subject to taxation in the United States but the tax is not expected to be material.
Revenue Recognition - Unbilled Revenue
Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. The determination of customer invoices is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the Great Britain distribution businesses, when information is received from the national settlement system. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $718 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's business platforms has established guidelines for credit risk management.
Commodity Price Risk
The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage and transmission and transportation constraints. The Company does not engage in a material amount of proprietary trading activities. To manage a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $26 million and $35 million, respectively, as of December 31, 2021 and 2020, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Not designated as hedging contracts | $ | 20 | | | $ | 116 | | | $ | (76) | |
Designated as hedging contracts | (10) | | | (5) | | | (15) | |
Total commodity derivative contracts | $ | 10 | | | $ | 111 | | | $ | (91) | |
| | | | | |
As of December 31, 2020: | | | | | |
Not designated as hedging contracts | $ | 103 | | | $ | 143 | | | $ | 63 | |
Designated as hedging contracts | (4) | | | 10 | | | (18) | |
Total commodity derivative contracts | $ | 99 | | | $ | 153 | | | $ | 45 | |
The settled cost of certain of the Company's commodity derivative contracts not designated as hedging contracts is included in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, wholesale natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms. As of December 31, 2021 and 2020, a net regulatory asset of $71 million and a net regulatory liability of $16 million, respectively, was recorded related to the net derivative asset of $20 million and $103 million, respectively. The difference between the net regulatory asset and the net derivative asset relates primarily to a power purchase agreement derivative at BHE Renewables. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts, to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility.
Interest Rate Risk
The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt, future debt issuances and mortgage commitments. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 9, 10, 11, and 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of the Company's short and long-term debt.
As of December 31, 2021 and 2020, the Company had short- and long-term variable-rate obligations totaling $3.7 billion and $4.4 billion, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. Changes in fair value of agreements designated as cash flow hedges are reported in AOCI to the extent the hedge is effective until the forecasted transaction occurs. Changes in fair value of agreements not designated as hedging contracts are recognized in earnings. As of December 31, 2021 and 2020, the Company had variable-to-fixed interest rate swaps with notional amounts of $533 million and $1,083 million, respectively, and £174 million and £121 million, respectively, to protect the Company against an increase in interest rates. Additionally, as of December 31, 2021 and 2020, the Company had mortgage commitments, net, with notional amounts of $1,512 million and $1,636 million, respectively, to protect the Company against an increase in interest rates. The fair value of the Company's interest rate derivative contracts was a net derivative asset of $16 million as of December 31, 2021 and a net derivative liability of $3 million as of December 31, 2020. A hypothetical 10 basis point increase and a 10 basis point decrease in interest rates would not have a material impact on the Company.
The Company holds foreign currency swaps with the purpose of hedging the foreign currency exchange rate associated with Euro denominated debt. As of December 31, 2021, the Company had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of the Company's foreign currency swaps as of December 31.
Equity Price Risk
Market prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.
As of December 31, 2021 and 2020, the Company's investment in BYD Company Limited common stock represented approximately 92% and 91%, respectively, of the total fair value of the Company's equity securities. The majority of the Company's remaining equity securities are held in a trust related to the decommissioning of nuclear generation assets and the realized and unrealized gains and losses are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. The following table summarizes the Company's investment in BYD Company Limited as of December 31, 2021 and 2020 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated | | Hypothetical |
| | | Hypothetical | | Fair Value after | | Percentage Increase |
| Fair | | Price | | Hypothetical | | (Decrease) in BHE |
| Value | | Change | | Change in Prices | | Shareholders' Equity |
| | | | | | | |
As of December 31, 2021 | $ | 7,693 | | | 30% increase | | $ | 10,001 | | | 3 | % |
| | | 30% decrease | | 5,385 | | | (3) | |
| | | | | | | |
As of December 31, 2020 | $ | 5,897 | | | 30% increase | | $ | 7,666 | | | 2 | % |
| | | 30% decrease | | 4,128 | | | (2) | |
Foreign Currency Exchange Rate Risk
BHE's business operations and investments outside of the United States increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound and the Canadian dollar. BHE's reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from BHE's foreign operations changes with the fluctuations of the currency in which they transact.
Northern Powergrid's functional currency is the British pound. As of December 31, 2021, a 10% devaluation in the British pound to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $506 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid of $25 million in 2021.
BHE Canada's functional currency is the Canadian dollar. As of December 31, 2021, a 10% devaluation in the Canadian dollar to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $384 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for BHE Canada of $19 million in 2021.
Credit Risk
Domestic Regulated Operations
The Utilities are exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.
Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2021, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
As of December 31, 2021, NV Energy's aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.
BHE GT&S primary customers include electric and natural gas distribution utilities and LNG export, import and storage customers. Northern Natural Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of BHE GT&S, Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until they meet the creditworthiness requirements of the respective tariff.
Northern Powergrid
The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to supply companies. The supply companies purchase electricity from generators and traders, sell the electricity to end-use customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses. During 2021, E.ON and certain of its affiliates and British Gas Trading Limited represented approximately 23% and 12%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. The industry operates in accordance with a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Northern Powergrid Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.
BHE Canada
AltaLink's primary source of operating revenue is the AESO, an entity rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $719 million for the year ended December 31, 2021.
BHE Renewables
BHE Renewables owns independent power projects that generally have separate project financing agreements. These projects source of operating revenue is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2023 and 2043. Because of the dependence generally from a single customer at each project, any material failure of the customer to fulfill its obligations would significantly impair that project's ability to meet its existing and future obligations. Total operating revenue for BHE Renewables was $981 million for the year ended December 31, 2021.
Other Energy Business
MES is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with financial institutions and other market participants. Credit risk may be concentrated to the extent that MES' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MES analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MES enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MES exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, MES' aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and the Shareholders of
Berkshire Hathaway Energy Company
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2021, the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 7 to the financial statements
Critical Audit Matter Description
The Company, through its regulated businesses, is subject to rate regulation by the Federal Energy Regulatory Commission as well as certain other regulatory commissions (collectively, the "Commissions"), which have jurisdiction with respect to the rates of the Company's regulated businesses in the respective service territories where the Company operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense and income tax expense (benefit).
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow the Company an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit the Company's ability to recover their costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated the Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
California and Oregon 2020 Wildfires — Contingencies — See Note 16 to the financial statements
Critical Audit Matter Description
The Company has loss contingencies related to the California and Oregon 2020 wildfires (the "2020 wildfires"). The Company has recorded estimated liabilities, net of expected insurance recoveries, of $136 million as of December 31, 2021, which represents its best estimate of probable losses, net of expected insurance recoveries, as a result of the 2020 wildfires.
We identified wildfire-related contingencies and the related disclosure as a critical audit matter because of the significant judgments made by management to estimate the losses. This required the application of a high degree of judgment and extensive effort when performing audit procedures to evaluate the reasonableness of management's estimate of the losses and disclosure related to wildfire-related loss contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding its estimate of losses for wildfire-related contingencies and the related disclosure included the following, among others:
•We evaluated management's judgments related to whether a loss was probable and reasonably estimable, reasonably possible, or remote for each individual wildfire by inquiring of management and the Company's external and internal legal counsel regarding the amounts of probable and reasonably estimable, reasonably possible, and remote losses, including the potential impact of information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire, and external information for any evidence that might contradict management's assertions.
•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management and its external and internal legal counsel.
•We tested the significant assumptions used in determining the estimate, including, but not limited to, information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire.
•We read legal letters from the Company's external and internal legal counsel regarding information regarding ongoing litigation related to the 2020 wildfires and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
February 25, 2022
We have served as the Company's auditor since 1991.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 1,096 | | | $ | 1,290 | |
Restricted cash and cash equivalents | 127 | | | 140 | |
Trade receivables, net | 2,468 | | | 2,107 | |
Inventories | 1,122 | | | 1,168 | |
Mortgage loans held for sale | 1,263 | | | 2,001 | |
Regulatory assets | 544 | | | 283 | |
Other current assets | 1,628 | | | 2,458 | |
Total current assets | 8,248 | | | 9,447 | |
| | | |
Property, plant and equipment, net | 89,816 | | | 86,128 | |
Goodwill | 11,650 | | | 11,506 | |
Regulatory assets | 3,419 | | | 3,157 | |
Investments and restricted cash and cash equivalents and investments | 15,788 | | | 14,320 | |
Other assets | 3,144 | | | 2,758 | |
| | | |
Total assets | $ | 132,065 | | | $ | 127,316 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 2,136 | | | $ | 1,867 | |
Accrued interest | 537 | | | 555 | |
Accrued property, income and other taxes | 606 | | | 582 | |
Accrued employee expenses | 372 | | | 383 | |
| | | |
Short-term debt | 2,009 | | | 2,286 | |
Current portion of long-term debt | 1,265 | | | 1,839 | |
Other current liabilities | 1,837 | | | 1,626 | |
Total current liabilities | 8,762 | | | 9,138 | |
| | | |
BHE senior debt | 13,003 | | | 12,997 | |
BHE junior subordinated debentures | 100 | | | 100 | |
Subsidiary debt | 35,394 | | | 34,930 | |
Regulatory liabilities | 6,960 | | | 7,221 | |
Deferred income taxes | 12,938 | | | 11,775 | |
Other long-term liabilities | 4,319 | | | 4,178 | |
Total liabilities | 81,476 | | | 80,339 | |
| | | |
Commitments and contingencies (Note 16) | 0 | | 0 |
| | | |
Equity: | | | |
BHE shareholders' equity: | | | |
Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding | 1,650 | | | 3,750 | |
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 6,374 | | | 6,377 | |
Long-term income tax receivable | (744) | | | (658) | |
Retained earnings | 40,754 | | | 35,093 | |
Accumulated other comprehensive loss, net | (1,340) | | | (1,552) | |
Total BHE shareholders' equity | 46,694 | | | 43,010 | |
Noncontrolling interests | 3,895 | | | 3,967 | |
Total equity | 50,589 | | | 46,977 | |
| | | |
Total liabilities and equity | $ | 132,065 | | | $ | 127,316 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
Energy | $ | 18,935 | | | $ | 15,556 | | | $ | 15,371 | |
Real estate | 6,215 | | | 5,396 | | | 4,473 | |
Total operating revenue | 25,150 | | | 20,952 | | | 19,844 | |
| | | | | |
Operating expenses: | | | | | |
Energy: | | | | | |
Cost of sales | 5,504 | | | 4,187 | | | 4,586 | |
Operations and maintenance | 3,991 | | | 3,545 | | | 3,318 | |
Depreciation and amortization | 3,829 | | | 3,410 | | | 2,965 | |
Property and other taxes | 789 | | | 634 | | | 574 | |
Real estate | 5,710 | | | 4,885 | | | 4,251 | |
Total operating expenses | 19,823 | | | 16,661 | | | 15,694 | |
| | | | | |
Operating income | 5,327 | | | 4,291 | | | 4,150 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (2,118) | | | (2,021) | | | (1,912) | |
Capitalized interest | 64 | | | 80 | | | 77 | |
Allowance for equity funds | 126 | | | 165 | | | 173 | |
Interest and dividend income | 89 | | | 71 | | | 117 | |
Gains (losses) on marketable securities, net | 1,823 | | | 4,797 | | | (288) | |
Other, net | (17) | | | 88 | | | 97 | |
Total other income (expense) | (33) | | | 3,180 | | | (1,736) | |
| | | | | |
Income before income tax (benefit) expense and equity loss | 5,294 | | | 7,471 | | | 2,414 | |
Income tax (benefit) expense | (1,132) | | | 308 | | | (598) | |
Equity loss | (237) | | | (149) | | | (44) | |
Net income | 6,189 | | | 7,014 | | | 2,968 | |
Net income attributable to noncontrolling interests | 399 | | | 71 | | | 18 | |
Net income attributable to BHE shareholders | 5,790 | | | 6,943 | | | 2,950 | |
Preferred dividends | 121 | | | 26 | | | — | |
Earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | 2,950 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 6,189 | | | $ | 7,014 | | | $ | 2,968 | |
| | | | | |
Other comprehensive income, net of tax: | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $55, $(19) and $(15) | 174 | | | (65) | | | (59) | |
Foreign currency translation adjustment | (24) | | | 234 | | | 327 | |
| | | | | |
Unrealized gains (losses) on cash flow hedges, net of tax of $10, $(3) and $(8) | 67 | | | (15) | | | (29) | |
Total other comprehensive income, net of tax | 217 | | | 154 | | | 239 | |
| | | | | |
Comprehensive income | 6,406 | | | 7,168 | | | 3,207 | |
Comprehensive income attributable to noncontrolling interests | 404 | | | 71 | | | 18 | |
Comprehensive income attributable to BHE shareholders | $ | 6,002 | | | $ | 7,097 | | | $ | 3,189 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| BHE Shareholders' Equity | | | | |
| | | | | | | Long-term | | | | Accumulated | | | | |
| | | | | Additional | | Income | | | | Other | | | | |
| Preferred | | Common | | Paid-in | | Tax | | Retained | | Comprehensive | | Noncontrolling | | Total |
| Stock | | Stock | | Capital | | Receivable | | Earnings | | Loss, Net | | Interests | | Equity |
| | | | | | | | | | | | | | | |
Balance, December 31, 2018 | $ | — | | | $ | — | | | $ | 6,371 | | | $ | (457) | | | $ | 25,624 | | | $ | (1,945) | | | $ | 130 | | | $ | 29,723 | |
Net income | — | | | — | | | — | | | — | | | 2,950 | | | — | | | 18 | | | 2,968 | |
Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 239 | | | — | | | 239 | |
Long-term income tax receivable adjustments | — | | | — | | | 33 | | | (73) | | | — | | | — | | | — | | | (40) | |
Common stock purchases | — | | | — | | | (15) | | | — | | | (278) | | | — | | | — | | | (293) | |
Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (22) | | | (22) | |
Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | 3 | | | 3 | |
Balance, December 31, 2019 | — | | | — | | | 6,389 | | | (530) | | | 28,296 | | | (1,706) | | | 129 | | | 32,578 | |
Net income | — | | | — | | | — | | | — | | | 6,943 | | | — | | | 70 | | | 7,013 | |
Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 154 | | | — | | | 154 | |
Long-term income tax receivable adjustments | — | | | — | | | — | | | (128) | | | — | | | — | | | — | | | (128) | |
Issuance of preferred stock | 3,750 | | | — | | | — | | | — | | | — | | | — | | | — | | | 3,750 | |
Preferred stock dividend | — | | | — | | | — | | | — | | | (26) | | | — | | | — | | | (26) | |
Common stock purchases | | | — | | | (6) | | | — | | | (120) | | | — | | | — | | | (126) | |
Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (121) | | | (121) | |
Purchase of noncontrolling interest | — | | | — | | | (5) | | | — | | | — | | | — | | | (28) | | | (33) | |
BHE GT&S acquisition - noncontrolling interest | — | | | — | | | — | | | — | | | — | | | — | | | 3,916 | | | 3,916 | |
Other equity transactions | — | | | — | | | (1) | | | — | | | — | | | — | | | 1 | | | — | |
Balance, December 31, 2020 | 3,750 | | | — | | | 6,377 | | | (658) | | | 35,093 | | | (1,552) | | | 3,967 | | | 46,977 | |
Net income | — | | | — | | | — | | | — | | | 5,790 | | | — | | | 397 | | | 6,187 | |
Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 212 | | | 5 | | | 217 | |
Long-term income tax receivable adjustments | — | | | — | | | — | | | (86) | | | (8) | | | — | | | — | | | (94) | |
Preferred stock redemptions | (2,100) | | | — | | | — | | | — | | | — | | | — | | | — | | | (2,100) | |
Preferred stock dividend | — | | | — | | | — | | | — | | | (121) | | | — | | | — | | | (121) | |
| | | | | | | | | | | | | | | |
Distributions | | | — | | | — | | | — | | | — | | | — | | | (478) | | | (478) | |
Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | |
Purchase of noncontrolling interest | — | | | — | | | (3) | | | — | | | — | | | — | | | (4) | | | (7) | |
Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | (1) | | | (1) | |
Balance, December 31, 2021 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,754 | | | $ | (1,340) | | | $ | 3,895 | | | $ | 50,589 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions) | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 6,189 | | | $ | 7,014 | | | $ | 2,968 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
(Gains) losses on marketable securities, net | (1,823) | | | (4,797) | | | 288 | |
Losses on other items, net | 112 | | | 54 | | | 43 | |
Depreciation and amortization | 3,881 | | | 3,455 | | | 3,011 | |
Allowance for equity funds | (126) | | | (165) | | | (173) | |
Equity loss, net of distributions | 380 | | | 248 | | | 93 | |
Changes in regulatory assets and liabilities | (668) | | | (415) | | | 153 | |
Deferred income taxes and investment tax credits, net | 646 | | | 1,880 | | | 290 | |
Other, net | (169) | | | (77) | | | 23 | |
Changes in other operating assets and liabilities, net of effects from acquisitions: | | | | | |
Trade receivables and other assets | 553 | | | (1,318) | | | (372) | |
Derivative collateral, net | 82 | | | 43 | | | (25) | |
Pension and other postretirement benefit plans | (39) | | | (65) | | | (51) | |
Accrued property, income and other taxes, net | (489) | | | (134) | | | (16) | |
Accounts payable and other liabilities | 163 | | | 501 | | | (26) | |
Net cash flows from operating activities | 8,692 | | | 6,224 | | | 6,206 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (6,611) | | | (6,765) | | | (7,364) | |
Acquisitions, net of cash acquired | (122) | | | (2,397) | | | (27) | |
Purchases of marketable securities | (297) | | | (370) | | | (262) | |
Proceeds from sales of marketable securities | 273 | | | 325 | | | 238 | |
Purchases of other investments | (20) | | | (1,323) | | | — | |
Proceeds from other investments | 1,300 | | | 13 | | | 18 | |
Equity method investments | (212) | | | (2,724) | | | (1,617) | |
Other, net | (74) | | | 76 | | | 51 | |
Net cash flows from investing activities | (5,763) | | | (13,165) | | | (8,963) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from issuance of preferred stock | — | | | 3,750 | | | — | |
Preferred stock redemptions | (2,100) | | | — | | | — | |
Preferred dividends | (132) | | | (7) | | | — | |
Common stock purchases | — | | | (126) | | | (293) | |
Proceeds from BHE senior debt | — | | | 5,212 | | | — | |
Repayments of BHE senior debt | (450) | | | (350) | | | — | |
Proceeds from subsidiary debt | 2,409 | | | 2,688 | | | 4,699 | |
Repayments of subsidiary debt | (2,024) | | | (2,841) | | | (1,914) | |
Net (repayments of) proceeds from short-term debt | (276) | | | (939) | | | 684 | |
Purchase of noncontrolling interest | — | | | (33) | | | — | |
Distributions to noncontrolling interests | (488) | | | (122) | | | (23) | |
Contributions from noncontrolling interests | 9 | | | 5 | | | 8 | |
Other, net | (79) | | | (134) | | | (37) | |
Net cash flows from financing activities | (3,131) | | | 7,103 | | | 3,124 | |
| | | | | |
Effect of exchange rate changes | 1 | | | 15 | | | 18 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (201) | | | 177 | | | 385 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 1,445 | | | 1,268 | | | 883 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 1,244 | | | $ | 1,445 | | | $ | 1,268 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)Organization and Operations
Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized as 8 business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables, LLC ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns 4 utility companies in the United States serving customers in 11 states, 2 electricity distribution companies in Great Britain, 5 interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and 1 of the largest residential real estate brokerage franchise networks in the United States.
(2)Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of BHE and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenue and expenses of any acquired entities from the date of acquisition. The Company consolidates variable interest entities ("VIE") in which it possesses both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Intercompany accounts and transactions have been eliminated.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; fair value of assets acquired and liabilities assumed in business combinations; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas, Kern River and AltaLink (the "Regulated Businesses") prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. Restricted amounts are included in restricted cash and cash equivalents and investments and restricted cash and cash equivalents and investments on the Consolidated Balance Sheets.
Investments
Fixed Maturity Securities
The Company's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments and restricted cash and cash equivalents and investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Consolidated Balance Sheets.
Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity investments are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.
Investment gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if the Company intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated fixed maturity investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.
Equity Securities
Investments in equity securities are carried at fair value with changes in fair value recognized in earnings as a component of gains (losses) on marketable securities, net. All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates.
Equity Method Investments
The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and OCI of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, the Company primarily utilizes credit loss history. However, the Company may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 77 | | | $ | 44 | | | $ | 42 | |
Charged to operating costs and expenses, net | 81 | | | 56 | | | 47 | |
Acquisitions | — | | | 5 | | | — | |
Write-offs, net | (50) | | | (28) | | | (45) | |
Ending balance | $ | 108 | | | $ | 77 | | | $ | 44 | |
Derivatives
The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.
For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.
For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
Inventories
Inventories consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $296 million and $382 million as of December 31, 2021 and 2020, respectively, and materials and supplies totaling $826 million and $786 million as of December 31, 2021 and 2020, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $27 million and $10 million higher as of December 31, 2021 and 2020, respectively.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the Regulated Businesses. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily related to the decommissioning of nuclear generating facilities and obligations associated with its other generating facilities and offshore natural gas pipelines. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
The Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
The Company's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, the Company estimates the fair value of its reporting units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the excess is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2021, 2020 and 2019, the Company did not record any material goodwill impairments.
The Company records goodwill adjustments for changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.
Revenue Recognition
Customer Revenue
The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations. In the event one of the parties to a contract has performed before the other, the Company would recognize a contract asset or contract liability depending on the relationship between the Company's performance and the customer's payment.
Energy Products and Services
A majority of the Company's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. The Company's energy revenue that is nonregulated primarily relates to the Company's renewable energy business.
Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $718 million and $750 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Real Estate Services
The Company's HomeServices reportable segment consists of separate brokerage, mortgage and franchise businesses. Rates charged for brokerage, mortgage and franchise real estate services are established through contractual arrangements that establish the transaction price and the allocation of the price amongst the separate performance obligations.
The full-service residential real estate brokerage business has performance obligations to deliver integrated real estate services including brokerage services, title and closing services, property and casualty insurance, home warranties, relocation services, and other home-related services to customers. All performance obligations related to the full-service residential real estate brokerage business are satisfied in less than one year at the point in time when a real estate transaction is closed or when services are provided. Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Payments for amounts billed are generally due from the customer at closing.
The franchise business operates a network that has performance obligations to provide the right to use certain brand names and other related service marks as well as to provide orientation programs, training and consultation services, advertising programs and other services to its franchisees. The performance obligations related to the franchise business are satisfied over time or when the services are provided. Franchise royalty fees are sales-based variable consideration and are based on a percentage of commissions earned by franchisees on real estate sales, which are recognized when the sale closes. Meetings and training revenue, referral fees, late fees, service fees and franchise termination fees are earned when services have been completed. Payments for amounts billed are generally due from the franchisee within 30 days of billing.
Other Revenue
Energy Products and Services
Other revenue consists primarily of revenue related to power purchase agreements not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging" and ASC 842, "Leases" and certain non-tariff-based revenue approved by the regulator that is not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."
Real Estate Service
Mortgage and other revenue consists primarily of revenue related to the mortgage business. Mortgage fee revenue consists of amounts earned related to application and underwriting fees, and fees on canceled loans. Fees associated with the origination of mortgage loans are recognized as earned. These amounts are not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging," ASC 825, "Financial Instruments" and ASC 860, "Transfers and Servicing."
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Foreign Currency
The accounts of foreign-based subsidiaries are measured in most instances using the local currency of the subsidiary as the functional currency. Revenue and expenses of these businesses are translated into United States dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in equity as a component of AOCI. Gains or losses arising from transactions denominated in a currency other than the functional currency of the entity that is party to the transaction are included in earnings.
Income Taxes
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company records the deferred income tax assets associated with the state of Iowa net operating loss carryforward as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity due to the long-term related party nature of the income tax receivable.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company's regulated businesses deems probable to be passed on to their customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions. The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely.
The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
(3) Business Acquisitions
BHE GT&S Acquisition
Transaction Description
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") and Carolina Gas Transmission, LLC; 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a 25% economic interest in Cove Point LNG, LP ("Cove Point"), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the United States Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.
On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI was also a party to the Q-Pipe Purchase Agreement, as guarantor for certain provisions regarding the Purchase Price Repayment Amount (as defined below) and other matters.
Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion, which was included in other current assets on the Consolidated Balance Sheet as of December 31, 2020, to Dominion Questar on November 2, 2020. Pursuant to the Q-Pipe Purchase Agreement, Dominion Questar agreed that, if the Q-Pipe Transaction did not close, it would repay all or (depending upon the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021.
On July 9, 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. On July 14, 2021, BHE received the Purchase Price Repayment Amount of approximately $1.3 billion in cash, which was included in proceeds from other investments on the Consolidated Statements of Cash Flows for the year ended December 31, 2021.
Included in BHE's Consolidated Statement of Operations within the BHE Pipeline Group reportable segment for the years ended December 31, 2021 and 2020, is operating revenue of $2,159 million and $331 million, respectively, and net income attributable to BHE shareholders of $316 million and $73 million, respectively, as a result of including BHE GT&S from November 1, 2020. Additionally, BHE incurred $9 million of direct transaction costs associated with the GT&S Transaction that are included in operating expense on the Consolidated Statement of Operations for the year ended December 31, 2020.
Allocation of Purchase Price
BHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the FERC and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.
The fair value of BHE GT&S' assets acquired and liabilities assumed not subject to the rate-setting provisions discussed above was determined using an income and cost approach. The income approach is based on significant estimates and assumptions, including Level 3 inputs, which are judgmental in nature. The estimates and assumptions include the projected timing and amount of future cash flows, discount rates reflecting the risk inherent in the future cash flows and future market prices. Additionally, the fair value of long-term debt assumed was determined based on quoted market prices, which is considered a Level 2 fair value measurement.
The following table summarizes the fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):
| | | | | | | | |
| | Fair Value |
| | |
Current assets, including cash and cash equivalents of $104 | | $ | 582 | |
Property, plant and equipment | | 9,264 | |
Goodwill | | 1,741 | |
Regulatory assets | | 108 | |
Deferred income taxes | | 284 | |
Other long-term assets | | 1,424 | |
Total assets | | 13,403 | |
| | |
Current liabilities, including current portion of long-term debt of $1,200 | | 1,616 | |
Long-term debt, less current portion | | 4,415 | |
Regulatory liabilities | | 650 | |
Other long-term liabilities | | 292 | |
Total liabilities | | 6,973 | |
Noncontrolling interest | | 3,916 | |
Net assets acquired | | $ | 2,514 | |
During the year ended December 31, 2021, the Company made revisions to certain contracts and property, plant and equipment related to non-regulated operations, the equity method investment and associated deferred income tax amounts based upon the receipt of additional information about the facts and circumstances that existed as of the acquisition date. Provisional amounts were subject to further revision for up to 12 months following the acquisition date until the related valuations were completed.
Goodwill
The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain items, book and tax goodwill will differ. The amount of tax goodwill is approximately $0.9 billion and will be amortized over 15 years.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of BHE and the amortization of the purchase price adjustments assuming the acquisition had taken place on January 1, 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):
| | | | | | | | | | | |
| 2020 | | 2019 |
| | | |
Operating revenue | $ | 22,581 | | | $ | 21,979 | |
| | | |
Net income attributable to BHE shareholders | $ | 6,800 | | | $ | 3,271 | |
Other
In 2021, the Company completed various other acquisitions of residential real estate brokerage businesses totaling $122 million, net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related to residential real estate brokerage businesses. As a result of the various acquisitions, the Company acquired assets of $54 million, assumed liabilities of $61 million and recognized goodwill of $129 million.
(4)Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable | | | | |
| Life | | 2021 | | 2020 |
Regulated assets: | | | | | |
Utility generation, transmission and distribution systems | 5-80 years | | $ | 90,223 | | | $ | 86,730 | |
Interstate natural gas pipeline assets | 3-80 years | | 17,423 | | | 16,667 | |
| | | 107,646 | | | 103,397 | |
Accumulated depreciation and amortization | | | (32,680) | | | (30,662) | |
Regulated assets, net | | | 74,966 | | | 72,735 | |
| | | | | |
Nonregulated assets: | | | | | |
Independent power plants | 2-50 years | | 7,665 | | | 7,012 | |
Cove Point LNG facility | 40 years | | 3,364 | | | 3,339 | |
Other assets | 2-30 years | | 2,666 | | | 2,320 | |
| | | 13,695 | | | 12,671 | |
Accumulated depreciation and amortization | | | (3,041) | | | (2,586) | |
Nonregulated assets, net | | | 10,654 | | | 10,085 | |
| | | | | |
Net operating assets | | | 85,620 | | | 82,820 | |
Construction work-in-progress | | | 4,196 | | | 3,308 | |
Property, plant and equipment, net | | | $ | 89,816 | | | $ | 86,128 | |
Construction work-in-progress includes $3.8 billion and $3.2 billion as of December 31, 2021 and 2020, respectively, related to the construction of regulated assets.
(5)Jointly Owned Utility Facilities
Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities.
The amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | Construction |
| Company | | Facility In | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
PacifiCorp: | | | | | | | |
Jim Bridger Nos. 1-4 | 67 | % | | $ | 1,523 | | | $ | 812 | | | $ | 15 | |
Hunter No. 1 | 94 | | | 489 | | | 221 | | | 8 | |
Hunter No. 2 | 60 | | | 306 | | | 138 | | | 1 | |
Wyodak | 80 | | | 477 | | | 269 | | | 8 | |
Colstrip Nos. 3 and 4 | 10 | | | 260 | | | 161 | | | 3 | |
Hermiston | 50 | | | 185 | | | 99 | | | — | |
Craig Nos. 1 and 2 | 19 | | | 369 | | | 319 | | | — | |
Hayden No. 1 | 25 | | | 77 | | | 47 | | | — | |
Hayden No. 2 | 13 | | | 44 | | | 28 | | | — | |
Transmission and distribution facilities | Various | | 879 | | | 269 | | | 118 | |
Total PacifiCorp | | | 4,609 | | | 2,363 | | | 153 | |
MidAmerican Energy: | | | | | | | |
Louisa No. 1 | 88 | % | | 864 | | | 501 | | | 20 | |
Quad Cities Nos. 1 and 2(1) | 25 | | | 732 | | | 452 | | | 9 | |
Walter Scott, Jr. No. 3 | 79 | | | 949 | | | 518 | | | 15 | |
Walter Scott, Jr. No. 4(2) | 60 | | | 225 | | | 134 | | | 8 | |
George Neal No. 4 | 41 | | | 318 | | | 184 | | | 4 | |
Ottumwa No. 1 | 52 | | | 674 | | | 264 | | | 11 | |
George Neal No. 3 | 72 | | | 528 | | | 286 | | | 9 | |
Transmission facilities | Various | | 263 | | | 100 | | | 4 | |
Total MidAmerican Energy | | | 4,553 | | | 2,439 | | | 80 | |
NV Energy: | | | | | | | |
Navajo | 11 | % | | 5 | | | 5 | | | — | |
Valmy | 50 | | | 394 | | | 309 | | | 1 | |
On Line Transmission Line | 25 | | | 160 | | | 31 | | | 1 | |
Transmission facilities | Various | | 65 | | | 34 | | | — | |
Total NV Energy | | | 624 | | | 379 | | | 2 | |
BHE Pipeline Group: | | | | | | | |
Ellisburg Pool | 39 | % | | 31 | | | 11 | | | 1 | |
Ellisburg Station | 50 | | | 26 | | | 8 | | | 1 | |
Harrison | 50 | | | 53 | | | 18 | | | — | |
Leidy | 50 | | | 132 | | | 46 | | | 7 | |
Oakford | 50 | | | 200 | | | 68 | | | 2 | |
Common Facilities | Various | | 276 | | | 166 | | | — | |
Total BHE Pipeline Group | | | 718 | | | 317 | | | 11 | |
Total | | | $ | 10,504 | | | $ | 5,498 | | | $ | 246 | |
(1)Includes amounts related to nuclear fuel.
(2)Facility in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa regulatory arrangements totaling $561 million and $127 million, respectively.
(6) Leases
The following table summarizes the Company's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 524 | | | $ | 517 | |
Finance leases | 448 | | | 501 | |
Total right-of-use assets | $ | 972 | | | $ | 1,018 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 577 | | | $ | 569 | |
Finance leases | 463 | | | 514 | |
Total lease liabilities | $ | 1,040 | | | $ | 1,083 | |
The following table summarizes the Company's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 611 | | | $ | 592 | | $ | 623 |
Operating | 161 | | | 151 | | 170 |
Finance: | | | | | |
Amortization | 23 | | | 18 | | 16 |
Interest | 38 | | | 40 | | 41 |
Short-term | 15 | | | 20 | | 7 |
Total lease costs | $ | 848 | | | $ | 821 | | $ | 857 |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 7.6 | | 7.4 | | 7.6 |
Finance leases | 28.1 | | 27.5 | | 28.8 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 4.3 | % | | 4.5 | % | | 5.2 | % |
Finance leases | 8.6 | % | | 8.5 | % | | 8.6 | % |
The following table summarizes the Company's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
Operating cash flows from operating leases | $ | (163) | | | $ | (152) | | | $ | (153) | |
Operating cash flows from finance leases | (38) | | | (40) | | | (42) | |
Financing cash flows from finance leases | (28) | | | (24) | | | (19) | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | |
Operating leases | $ | 119 | | | $ | 83 | | | $ | 82 | |
Finance leases | 2 | | | 19 | | | 14 | |
The Company has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 157 | | | $ | 72 | | | $ | 229 | |
2023 | 124 | | | 62 | | | 186 | |
2024 | 93 | | | 62 | | | 155 | |
2025 | 71 | | | 60 | | | 131 | |
2026 | 55 | | | 60 | | | 115 | |
Thereafter | 186 | | | 607 | | | 793 | |
Total undiscounted lease payments | 686 | | | 923 | | | 1,609 | |
Less - amounts representing interest | (109) | | | (460) | | | (569) | |
Lease liabilities | $ | 577 | | | $ | 463 | | | $ | 1,040 | |
(7)Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future regulated rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Asset retirement obligations | 14 years | | $ | 742 | | | $ | 640 | |
Deferred net power costs | 1 year | | 531 | | | 139 | |
Employee benefit plans(1) | 15 years | | 472 | | | 722 | |
Deferred income taxes(2) | Various | | 342 | | | 283 | |
Asset disposition costs | Various | | 285 | | | 347 | |
Demand side management | 10 years | | 211 | | | 197 | |
Unrealized loss on regulated derivative contracts | Various | | 157 | | | 31 | |
Environmental costs | 28 years | | 108 | | | 89 | |
Deferred operating costs | 9 years | | 103 | | | 124 | |
Other | Various | | 1,012 | | | 868 | |
Total regulatory assets | | | $ | 3,963 | | | $ | 3,440 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 544 | | | $ | 283 | |
Noncurrent assets | | | 3,419 | | | 3,157 | |
Total regulatory assets | | | $ | 3,963 | | | $ | 3,440 | |
(1)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
(2)Amounts primarily represent income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
The Company had regulatory assets not earning a return on investment of $1.8 billion and $1.6 billion as of December 31, 2021 and 2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 3,185 | | | $ | 3,600 | |
Cost of removal(2) | 26 years | | 2,424 | | | 2,435 | |
Asset retirement obligations | 31 years | | 345 | | | 305 | |
Levelized depreciation | 29 years | | 259 | | | 281 | |
Employee benefit plans(3) | Various | | 243 | | | 187 | |
Other | Various | | 758 | | | 667 | |
Total regulatory liabilities | | | $ | 7,214 | | | $ | 7,475 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 254 | | | $ | 254 | |
Noncurrent liabilities | | | 6,960 | | | 7,221 | |
Total regulatory liabilities | | | $ | 7,214 | | | $ | 7,475 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(3)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be returned to customers in future periods when recognized.
(8)Investments and Restricted Cash and Cash Equivalents and Investments
Investments and restricted cash and cash equivalents and investments consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Investments: | | | |
BYD Company Limited common stock | $ | 7,693 | | | $ | 5,897 | |
Rabbi trusts | 492 | | | 440 | |
Other | 305 | | | 263 | |
Total investments | 8,490 | | | 6,600 | |
| | | |
Equity method investments: | | | |
BHE Renewables tax equity investments | 4,931 | | | 5,626 | |
Iroquois Gas Transmission System, L.P. | 735 | | | 580 | |
Electric Transmission Texas, LLC | 595 | | | 594 | |
JAX LNG, LLC | 92 | | | 75 | |
Bridger Coal Company | 45 | | | 74 | |
Other | 156 | | | 118 | |
Total equity method investments | 6,554 | | | 7,067 | |
| | | |
Restricted cash and cash equivalents and investments: | | | |
Quad Cities Station nuclear decommissioning trust funds | 768 | | | 676 | |
Other restricted cash and cash equivalents | 148 | | | 155 | |
Total restricted cash and cash equivalents and investments | 916 | | | 831 | |
| | | |
Total investments and restricted cash and cash equivalents and investments | $ | 15,960 | | | $ | 14,498 | |
| | | |
Reflected as: | | | |
Other current assets | $ | 172 | | | $ | 178 | |
Noncurrent assets | 15,788 | | | 14,320 | |
Total investments and restricted cash and cash equivalents and investments | $ | 15,960 | | | $ | 14,498 | |
Investments
BHE's investment in BYD Company Limited common stock is accounted for as a marketable security with changes in fair value recognized in net income.
Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value.
Gains (losses) on marketable securities, net recognized during the period consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Unrealized gains (losses) recognized on marketable securities held at the reporting date | $ | 1,819 | | | $ | 4,791 | | | $ | (290) | |
Net gains recognized on marketable securities sold during the period | 4 | | | 6 | | | 2 | |
Gains (losses) on marketable securities, net | $ | 1,823 | | | $ | 4,797 | | | $ | (288) | |
Equity Method Investments
The Company has invested in wind projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $— million, $2,736 million and $1,619 million in 2021, 2020 and 2019, respectively, and has commitments as of December 31, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $356 million in 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
BHE, through separate subsidiaries, owns (i) 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut; (ii) 50% of Electric Transmission Texas, LLC, which owns and operates electric transmission assets in the Electric Reliability Council of Texas footprint; (iii) 50% of JAX LNG, LLC, which is an LNG supplier in Florida serving the growing marine and truck LNG markets; and (iv) 66.67% of Bridger Coal Company ("Bridger Coal"), which is a coal mining joint venture that supplies coal to the Jim Bridger Nos. 1-4 generating facility. Bridger Coal is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner.
Restricted Investments
MidAmerican Energy has established a trust for the investment of funds for decommissioning the Quad Cities Nuclear Station Units 1 and 2 ("Quad Cities Station"). The debt and equity securities in the trust are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station, which are currently licensed for operation until December 2032.
(9)Short-term Debt and Credit Facilities
The following table summarizes BHE's and its subsidiaries' availability under their credit facilities as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Total(1) |
2021: | | | | | | | | | | | | | | | |
Credit facilities(2) | $ | 3,500 | | | $ | 1,200 | | | $ | 1,509 | | | $ | 650 | | | $ | 271 | | | $ | 851 | | | $ | 3,300 | | | $ | 11,281 | |
Less: | | | | | | | | | | | | | | | |
Short-term debt | — | | | — | | | — | | | (339) | | | (1) | | | (245) | | | (1,424) | | | (2,009) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | (589) | |
Net credit facilities | $ | 3,500 | | | $ | 982 | | | $ | 1,139 | | | $ | 311 | | | $ | 270 | | | $ | 605 | | | $ | 1,876 | | | $ | 8,683 | |
| | | | | | | | | | | | | | | |
2020: | | | | | | | | | | | | | | | |
Credit facilities(2) | $ | 3,500 | | | $ | 1,200 | | | $ | 1,509 | | | $ | 650 | | | $ | 228 | | | $ | 923 | | | $ | 3,020 | | | $ | 11,030 | |
Less: | | | | | | | | | | | | | | | |
Short-term debt | — | | | (93) | | | — | | | (45) | | | (23) | | | (225) | | | (1,900) | | | (2,286) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (2) | | | — | | | (590) | |
Net credit facilities | $ | 3,500 | | | $ | 889 | | | $ | 1,139 | | | $ | 605 | | | $ | 205 | | | $ | 696 | | | $ | 1,120 | | | $ | 8,154 | |
(1)The table does not include unused credit facilities and letters of credit for investments that are accounted for under the equity method.
(2)Includes drawn uncommitted credit facilities totaling $1 million and $23 million, respectively, at Northern Powergrid as of December 31, 2021 and 2020.
As of December 31, 2021, the Company was in compliance with the covenants of its credit facilities and letter of credit arrangements.
BHE
BHE has a $3.5 billion unsecured credit facility expiring in June 2024 with an unlimited number of maturity extension options subject to lender consent. This credit facility, which is for general corporate purposes, supports BHE's commercial paper program and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at BHE's option, plus a spread that varies based on BHE's credit ratings for its senior unsecured long-term debt securities.
As of December 31, 2021 and 2020, BHE did not have any commercial paper borrowings outstanding. The credit facility requires that BHE's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter.
As of December 31, 2021 and 2020, BHE had $101 million and $105 million, respectively, of letters of credit outstanding. These letters of credit primarily support power purchase agreements and debt service requirements at certain subsidiaries of BHE Renewables, LLC expiring through April 2023 and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
PacifiCorp
PacifiCorp has a $1.2 billion unsecured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.
As of December 31, 2021, PacifiCorp did not have any commercial paper borrowings outstanding. As of December 31, 2020, PacifiCorp had $93 million of commercial paper outstanding with a weighted average interest rate of 0.16%. The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2021 and 2020, PacifiCorp had $19 million and $11 million, respectively, of fully available letters of credit issued under committed arrangements in support of certain transactions required by third parties and generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
MidAmerican Funding
As of December 31, 2021, MidAmerican Energy has $1.5 billion unsecured credit facility expiring in June 2024. In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring June 2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities.
As of December 31, 2020, in addition to the $900 million unsecured credit facility discussed above, MidAmerican Energy had a $600 million unsecured credit facility expiring August 2021, which was terminated in June 2021. As of December 31, 2021 and 2020, MidAmerican Energy had no commercial paper borrowings outstanding. The $1.5 billion credit facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter.
NV Energy
Nevada Power has a $400 million secured credit facility expiring in June 2024 and Sierra Pacific has a $250 million secured credit facility expiring in June 2024 each with an unlimited number of maturity extension options, subject to lender consent. These credit facilities, which are for general corporate purposes and provide for the issuance of letters of credit, have a variable interest rate based on the Eurodollar rate or a base rate, at each of the Nevada Utilities' option, plus a spread that varies based on each of the Nevada Utilities' credit ratings for its senior secured long‑term debt securities. As of December 31, 2021 and 2020, the Nevada Utilities had borrowings of $339 million and $45 million outstanding under these credit facilities at a weighted average interest rate of 0.86% and 0.90%, respectively. Amounts due under each credit facility are collateralized by each of the Nevada Utilities' general and refunding mortgage bonds. These credit facilities require that each of the Nevada Utilities' ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
Northern Powergrid
Northern Powergrid has a £200 million unsecured credit facility expiring in December 2024 with 2 one-year maturity extension options. The credit facility has a variable interest rate based on Sterling Overnight Index Average plus a spread that varies based on Northern Powergrid's credit ratings and a credit adjustment spread that varies based on the tenor of any borrowings. The credit facility requires that the ratio of consolidated senior total net debt, including current maturities, to regulated asset value not exceed 0.8 to 1.0 at Northern Powergrid and 0.65 to 1.0 at each of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc as of June 30 and December 31. Northern Powergrid's interest coverage ratio shall not be less than 2.5 to 1.0.
AltaLink
AltaLink has a C$500 million secured revolving term credit facility expiring in December 20232026 with a recurring one-year extension option subject to lender consent. The credit facility, which provides support for borrowings under the unsecuredsupports AltaLink's commercial paper program and may also be used for general corporate purposes, has a variable interest rate based on the Canadian bank prime lending rate or a spread above the Bankers' Acceptance rate, at ALP'sAltaLink's option, based on ALP'sAltaLink's credit ratings for its senior secured long-term debt securities. In addition, ALPAltaLink has a C$75 million secured revolving term credit facility expiring in December 20232026 with a recurring one-year extension option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit, has a variable interest rate based on the Canadian bank prime lending rate, United States base rate, a spread above the United States LIBOR loan rate or a spread above the Bankers' Acceptance rate, at ALP'sAltaLink's option, based on ALP'sAltaLink's credit ratings for its senior secured long-term debt securities.
As of December 31, 20182021 and 2017, ALP2020, AltaLink had $281$108 million and $121$113 million outstanding under these facilities at a weighted average interest rate of 2.26%0.35% and 1.42%0.36%, respectively. The credit facilities require the ratio of consolidated indebtedness to total capitalization not exceed 0.75 to 1.0 measured as of the last day of each quarter.
AltaLink Investments, L.P. has a C$300 million unsecured revolving term credit facility expiring in December 20232026 with a recurring one-year extension option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit to a maximum of C$10 million, has a variable interest rate based on the Canadian bank prime lending rate, United States base rate, or a spread above the Bankers' Acceptance rate, at AltaLink Investments, L.P.'s option, based on AltaLink Investments, L.P.'s credit ratings for its senior unsecured long-term debt securities.
AltaLink Investments, L.P. also has a C$200 million revolving term credit facility expiring in April 2022 with a recurring one-year extension option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit to a maximum of C$10 million, has a variable interest rate based on the Canadian bank prime lending rate, United States LIBOR loanbase rate, or a spread above the Bankers' Acceptance rate, at AltaLink Investments, L.P.'s option, based on AltaLink Investments, L.P.'s credit ratings for its senior unsecured long-term debt securities. On an annual basis, with the consent of the lenders, AltaLink Investments, L.P. can request that the maturity date of the credit facility be extended for a further 365 days.
As of December 31, 20182021 and 2017,2020, AltaLink Investments, L.P. had $64$137 million and $224$112 million outstanding under this facility at a weighted average interest rate of 3.25%1.46% and 2.40%1.47%, respectively. The credit facility requiresfacilities require the ratio of consolidated total debt to capitalization to not exceed 0.8 to 1.0 and earnings before interest, taxes, depreciation and amortization to interest expense for the four fiscal quarters ended to not be less than 2.25 to 1.0 measured as of the last day of each quarter.
HomeServices
HomeServices has a $600an $700 million unsecured credit facility expiring in September 2022.2026. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the LIBOR or a base rate, at HomeServices' option, plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter. As of December 31, 20182021 and 2017,2020, HomeServices had $404$250 million and $292$100 million, respectively, outstanding under its credit facility with a weighted average interest rate of 3.94%0.95% and 2.75%1.15%, respectively.
Through its subsidiaries, HomeServices maintains mortgage lines of credit totaling $985 million$2.6 billion and $1.0$2.4 billion as of December 31, 20182021 and 2017,2020, respectively, used for mortgage banking activities that expire beginning in January 2019February 2022 through December 2019 or are due on demand.September 2022. The mortgage lines of credit have variable rates based on LIBOR plus a spread. Collateral for these credit facilities is comprised of residential property being financed and is equal to the loans funded with the facilities. As of December 31, 20182021 and 2017,2020, HomeServices had $436 million$1.2 billion and $440 million,$1.8 billion, respectively, outstanding under these mortgage lines of credit at a weighted average interest rate of 4.42%1.91% and 3.60%2.03%, respectively.
BHE Renewables Letters of Credit
Topaz and Solar Star have separate letter of credit and reimbursement facilities used to (a) provide security under the power purchase agreement and large generator interconnection agreements, (b) fund the debt service reserve requirement and the operation and maintenance debt service reserve requirement and (c) provide security for remediation and mitigation liabilities. As of December 31, 2018, Topaz had $127 million of letters of credit issued under its $134 million facility2021 and Solar Star had $92 million of letters of credit issued under its $105 million facility. As of December 31, 2017, Topaz had $75 million of letters of credit issued under its $134 million facility and Solar Star had $282 million of letters of credit issued under its $301 million facility.
As of December 31, 2018and 2017,2020, certain other renewable projects collectively have letters of credit outstanding of $103$311 million and $118$305 million, respectively, primarily in support of the power purchase agreements and large generator interconnection agreements associated with the projects.
(10)BHE Debt
Senior Debt
BHE senior debt represents unsecured senior obligations of BHE that are redeemable in whole or in part at any time generally with make-whole premiums. BHE senior debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
| | | | | |
2.375% Senior Notes, due 2021 | $ | — | | | $ | — | | | $ | 448 | |
2.80% Senior Notes, due 2023 | 400 | | | 398 | | | 398 | |
3.75% Senior Notes, due 2023 | 500 | | | 499 | | | 498 | |
3.50% Senior Notes, due 2025 | 400 | | | 398 | | | 398 | |
4.05% Senior Notes, due 2025 | 1,250 | | | 1,246 | | | 1,246 | |
3.25% Senior Notes, due 2028 | 600 | | | 594 | | | 594 | |
8.48% Senior Notes, due 2028 | 256 | | | 260 | | | 257 | |
3.70% Senior Notes, due 2030 | 1,100 | | | 1,096 | | | 1,096 | |
1.65% Senior Notes, due 2031 | 500 | | | 497 | | | 497 | |
6.125% Senior Bonds, due 2036 | 1,670 | | | 1,661 | | | 1,661 | |
5.95% Senior Bonds, due 2037 | 550 | | | 548 | | | 548 | |
6.50% Senior Bonds, due 2037 | 225 | | | 223 | | | 223 | |
5.15% Senior Notes, due 2043 | 750 | | | 740 | | | 740 | |
4.50% Senior Notes, due 2045 | 750 | | | 738 | | | 738 | |
3.80% Senior Notes, due 2048 | 750 | | | 738 | | | 738 | |
4.45% Senior Notes, due 2049 | 1,000 | | | 990 | | | 990 | |
4.25% Senior Notes, due 2050 | 900 | | | 889 | | | 889 | |
2.85% Senior Notes, due 2051 | 1,500 | | | 1,488 | | | 1,488 | |
Total BHE Senior Debt | $ | 13,101 | | | $ | 13,003 | | | $ | 13,447 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | — | | | $ | 450 | |
Noncurrent liabilities | | | 13,003 | | | 12,997 | |
Total BHE Senior Debt | | | $ | 13,003 | | | $ | 13,447 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
| | | | | |
5.75% Senior Notes, due 2018 | — |
| | — |
| | 650 |
|
2.00% Senior Notes, due 2018 | — |
| | — |
| | 350 |
|
2.40% Senior Notes, due 2020 | 350 |
| | 349 |
| | 349 |
|
2.375% Senior Notes, due 2021 | 450 |
| | 448 |
| | — |
|
2.80% Senior Notes, due 2023 | 400 |
| | 398 |
| | — |
|
3.75% Senior Notes, due 2023 | 500 |
| | 498 |
| | 498 |
|
3.50% Senior Notes, due 2025 | 400 |
| | 398 |
| | 398 |
|
3.250% Senior Notes, due 2028 | 600 |
| | 594 |
| | — |
|
8.48% Senior Notes, due 2028 | 256 |
| | 257 |
| | 302 |
|
6.125% Senior Bonds, due 2036 | 1,670 |
| | 1,661 |
| | 1,660 |
|
5.95% Senior Bonds, due 2037 | 550 |
| | 547 |
| | 547 |
|
6.50% Senior Bonds, due 2037 | 225 |
| | 222 |
| | 222 |
|
5.15% Senior Notes, due 2043 | 750 |
| | 740 |
| | 739 |
|
4.50% Senior Notes, due 2045 | 750 |
| | 738 |
| | 737 |
|
3.80% Senior Notes, due 2048 | 750 |
| | 737 |
| | — |
|
4.45% Senior Notes, due 2049 | 1,000 |
| | 990 |
| | — |
|
Total BHE Senior Debt | $ | 8,651 |
| | $ | 8,577 |
| | $ | 6,452 |
|
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | — |
| | $ | 1,000 |
|
Noncurrent liabilities | | | 8,577 |
| | 5,452 |
|
Total BHE Senior Debt | | | $ | 8,577 |
| | $ | 6,452 |
|
Junior Subordinated Debentures
BHE junior subordinated debentures consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
| | | | | |
5.00% Junior subordinated debentures, due 2057 | 100 | | | 100 | | | 100 | |
Total BHE junior subordinated debentures - noncurrent | $ | 100 | | | $ | 100 | | | $ | 100 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
| | | | | |
Junior subordinated debentures, due 2057 | 100 |
| | 100 |
| | 100 |
|
Total BHE junior subordinated debentures - noncurrent | $ | 100 |
| | $ | 100 |
| | $ | 100 |
|
In June 2017, BHE issued $100 million of its 5.00%The junior subordinated debentures due June 2057 in exchange for 181,819 shares of BHE no par value common stockare held by a minority shareholder. The junior subordinated debenturesshareholder and are redeemable at BHE's option at any time from and after June 15, 2037, at par plus accrued and unpaid interest. Interest expense to the minority shareholder was $5 million for each of the yearyears ended December 31, 20182021, 2020 and 2017 was $5 million and $3 million, respectively.2019.
(11)Subsidiary Debt
BHE's direct and indirect subsidiaries are organized as legal entities separate and apart from BHE and its other subsidiaries. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties; the equity interest of MidAmerican Funding's subsidiary; MidAmerican Energy's electric utility properties in the state of Iowa; substantially all of Nevada Power's and Sierra Pacific's properties in the state of Nevada; AltaLink's transmission properties; and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solarwind and windsolar generation projects are pledged or encumbered to support or otherwise provide the security for their related subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The long-term debt of BHE's subsidiaries may include provisions that allow BHE's subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums.
Distributions at these separate legal entities are limited by various covenants including, among others, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2018,2021, all subsidiaries were in compliance with their long-term debt covenants. On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California. As a result, the Company does not expect to receive distributions from Topaz Solar Farms LLC ("Topaz") or Agua Caliente Solar, LLC ("Agua Caliente") in the near term.
Long-term debt of subsidiaries consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
| | | | | |
PacifiCorp | $ | 8,797 | | | $ | 8,730 | | | $ | 8,612 | |
MidAmerican Funding | 8,047 | | | 7,946 | | | 7,431 | |
NV Energy | 3,701 | | | 3,675 | | | 3,673 | |
Northern Powergrid | 3,321 | | | 3,287 | | | 3,259 | |
BHE Pipeline Group | 5,534 | | | 5,924 | | | 6,165 | |
BHE Transmission | 3,924 | | | 3,906 | | | 3,877 | |
BHE Renewables | 3,073 | | | 3,043 | | | 3,116 | |
HomeServices | 148 | | | 148 | | | 186 | |
Total subsidiary debt | $ | 36,545 | | | $ | 36,659 | | | $ | 36,319 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 1,265 | | | $ | 1,389 | |
Noncurrent liabilities | | | 35,394 | | | 34,930 | |
Total subsidiary debt | | | $ | 36,659 | | | $ | 36,319 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
| | | | | |
PacifiCorp | $ | 7,076 |
| | $ | 7,036 |
| | $ | 7,025 |
|
MidAmerican Funding | 5,668 |
| | 5,599 |
| | 5,259 |
|
NV Energy | 4,321 |
| | 4,318 |
| | 4,581 |
|
Northern Powergrid | 2,621 |
| | 2,626 |
| | 2,805 |
|
BHE Pipeline Group | 1,050 |
| | 1,042 |
| | 796 |
|
BHE Transmission | 3,856 |
| | 3,842 |
| | 4,334 |
|
BHE Renewables | 3,438 |
| | 3,401 |
| | 3,594 |
|
HomeServices | 233 |
| | 233 |
| | 247 |
|
Total subsidiary debt | $ | 28,263 |
| | $ | 28,097 |
| | $ | 28,641 |
|
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 2,106 |
| | $ | 2,431 |
|
Noncurrent liabilities | | | 25,991 |
| | 26,210 |
|
Total subsidiary debt | | | $ | 28,097 |
| | $ | 28,641 |
|
PacifiCorp
PacifiCorp's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
First mortgage bonds: | | | | | |
2.95% to 8.53%, due through 2026 | $ | 1,379 | | | $ | 1,378 | | | $ | 2,245 | |
2.70% to 7.70%, due 2027 to 2031 | 1,100 | | | 1,094 | | | 1,094 | |
5.25% to 6.10%, due 2032 to 2036 | 850 | | | 845 | | | 845 | |
5.75% to 6.35%, due 2037 to 2041 | 2,150 | | | 2,137 | | | 2,137 | |
4.10%, due 2042 | 300 | | | 297 | | | 297 | |
2.90% to 4.15%, due 2049 to 2052 | 2,800 | | | 2,761 | | | 1,776 | |
Variable-rate series, tax-exempt bond obligations (2021-0.12% to 0.13%; 2020-0.14% to 0.16%): | | | | | |
Due 2025 | 25 | | | 25 | | | 25 | |
Due 2024 to 2025(1) | 193 | | | 193 | | | 193 | |
Total PacifiCorp | $ | 8,797 | | | $ | 8,730 | | | $ | 8,612 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
First mortgage bonds: | | | | | |
2.95% to 8.53%, due through 2023 | $ | 1,824 |
| | $ | 1,821 |
| | $ | 2,320 |
|
3.35% to 6.71%, due 2024 to 2026 | 775 |
| | 771 |
| | 771 |
|
7.70% due 2031 | 300 |
| | 298 |
| | 298 |
|
5.25% to 6.35%, due 2034 to 2038 | 2,350 |
| | 2,338 |
| | 2,337 |
|
4.10% to 6.00%, due 2039 to 2042 | 950 |
| | 939 |
| | 938 |
|
4.125%, due 2049 | 600 |
| | 593 |
| | — |
|
Variable-rate series, tax-exempt bond obligations (2018-1.67% to 1.85%; 2017-1.60% to 1.87%): | | | | | |
Due 2018 to 2020 | 38 |
| | 38 |
| | 79 |
|
Due 2018 to 2025(1) | 25 |
| | 25 |
| | 70 |
|
Due 2024(1)(2) | 143 |
| | 142 |
| | 142 |
|
Due 2024 to 2025(2) | 50 |
| | 50 |
| | 50 |
|
Capital lease obligations - 8.75% to 14.61%, due through 2035 | 21 |
| | 21 |
| | 20 |
|
Total PacifiCorp | $ | 7,076 |
| | $ | 7,036 |
| | $ | 7,025 |
|
| |
(1) | Supported by $170 million and $216 million of fully available letters of credit issued under committed bank arrangements as of December 31, 2018 and 2017, respectively. |
| |
(2) | Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations. |
(1)Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $28$31 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2018.2021.
MidAmerican Funding
MidAmerican Funding's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
MidAmerican Funding: | | | | | |
6.927% Senior Bonds, due 2029 | $ | 239 | | | $ | 225 | | | $ | 221 | |
| | | | | |
MidAmerican Energy: | | | | | |
Tax-exempt bond obligations - | | | | | |
Variable-rate tax-exempt bond obligation series: (weighted average interest rate - 2021-0.13%, 2020-0.14%), due 2023-2047 | 370 | | | 368 | | | 368 | |
First Mortgage Bonds: | | | | | |
3.70%, due 2023 | 250 | | | 250 | | | 249 | |
3.50%, due 2024 | 500 | | | 501 | | | 501 | |
3.10%, due 2027 | 375 | | | 373 | | | 373 | |
3.65%, due 2029 | 850 | | | 860 | | | 862 | |
4.80%, due 2043 | 350 | | | 346 | | | 346 | |
4.40%, due 2044 | 400 | | | 395 | | | 395 | |
4.25%, due 2046 | 450 | | | 446 | | | 445 | |
3.95%, due 2047 | 475 | | | 470 | | | 470 | |
3.65%, due 2048 | 700 | | | 689 | | | 689 | |
4.25%, due 2049 | 900 | | | 874 | | | 873 | |
3.15%, due 2050 | 600 | | | 592 | | | 592 | |
2.70%, due 2052 | 500 | | | 492 | | | — | |
Notes: | | | | | |
6.75% Series, due 2031 | 400 | | | 397 | | | 397 | |
5.75% Series, due 2035 | 300 | | | 298 | | | 298 | |
5.80% Series, due 2036 | 350 | | | 348 | | | 348 | |
Transmission upgrade obligation, 3.35% to 7.95%, due 2036 to 2041 | 38 | | | 22 | | | 4 | |
Total MidAmerican Energy | 7,808 | | | 7,721 | | | 7,210 | |
Total MidAmerican Funding | $ | 8,047 | | | $ | 7,946 | | | $ | 7,431 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
MidAmerican Funding: | | | | | |
6.927% Senior Bonds, due 2029 | $ | 240 |
| | $ | 217 |
| | $ | 216 |
|
| | | | | |
MidAmerican Energy: | | | | | |
Tax-exempt bond obligations - | | | | | |
Variable-rate tax-exempt bond obligation series: (2018-1.74%, 2017-1.91%), due 2023-2047 | 370 |
| | 368 |
| | 368 |
|
First Mortgage Bonds: | | | | | |
2.40%, due 2019 | 500 |
| | 500 |
| | 499 |
|
3.70%, due 2023 | 250 |
| | 249 |
| | 248 |
|
3.50%, due 2024 | 500 |
| | 501 |
| | 501 |
|
3.10%, due 2027 | 375 |
| | 372 |
| | 372 |
|
4.80%, due 2043 | 350 |
| | 346 |
| | 346 |
|
4.40%, due 2044 | 400 |
| | 394 |
| | 394 |
|
4.25%, due 2046 | 450 |
| | 445 |
| | 445 |
|
3.95%, due 2047 | 475 |
| | 470 |
| | 470 |
|
3.65%, due 2048 | 700 |
| | 688 |
| | — |
|
Notes: | | | | | |
5.30% Series, due 2018 | — |
| | — |
| | 350 |
|
6.75% Series, due 2031 | 400 |
| | 396 |
| | 396 |
|
5.75% Series, due 2035 | 300 |
| | 298 |
| | 298 |
|
5.80% Series, due 2036 | 350 |
| | 348 |
| | 348 |
|
Transmission upgrade obligation, 4.45% and 3.42% due through 2035 and 2036, respectively | 7 |
| | 5 |
| | 6 |
|
Capital lease obligations - 4.16%, due through 2020 | 1 |
| | 2 |
| | 2 |
|
Total MidAmerican Energy | 5,428 |
| | 5,382 |
| | 5,043 |
|
Total MidAmerican Funding | $ | 5,668 |
| | $ | 5,599 |
| | $ | 5,259 |
|
In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest.
Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as amended by the First Supplemental Indenture dated as of September 19, 2013, MidAmerican Energy's first mortgage bonds, currently and from time to time outstanding, are secured by a first mortgage lien on substantially all of its electric generating, transmission and distribution property within the state of Iowa, subject to certain exceptions and permitted encumbrances. As of December 31, 2018,2021, MidAmerican Energy's eligible property subject to the lien of the mortgage totaled approximately $18$22 billion based on original cost. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.
MidAmerican Energy's variable-rate tax-exempt obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy, at its option, may change the mode of interest calculation for these bonds by selecting from among several floating or fixed rate alternatives. The interest rates shown in the table above are the weighted average interest rates as of December 31, 20182021 and 2017.2020. MidAmerican Energy maintains revolving credit facility agreements to provide liquidity for holders of these issues and $180 million of the variable rate, tax-exempt bonds are secured by an equal amount of first mortgage bonds pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as supplemented and amended.
NV Energy
NV Energy's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
| | | | | |
| | | | | |
| | | | | |
Nevada Power: | | | | | |
General and refunding mortgage securities: | | | | | |
| | | | | |
3.700% Series CC, due 2029 | $ | 500 | | | $ | 497 | | | $ | 496 | |
2.400% Series DD, due 2030 | 425 | | | 422 | | | 422 | |
6.650% Series N, due 2036 | 367 | | | 361 | | | 361 | |
6.750% Series R, due 2037 | 349 | | | 347 | | | 347 | |
5.375% Series X, due 2040 | 250 | | | 249 | | | 249 | |
5.450% Series Y, due 2041 | 250 | | | 246 | | | 244 | |
3.125% Series EE, due 2050 | 300 | | | 297 | | | 297 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.875% Pollution Control Bonds Series 2017A, due 2032(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017, due 2036(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017B, due 2039(1) | 13 | | | 13 | | | 13 | |
Total Nevada Power | 2,534 | | | 2,510 | | | 2,507 | |
| | | | | |
Sierra Pacific: | | | | | |
General and refunding mortgage securities: | | | | | |
3.375% Series T, due 2023 | 250 | | | 249 | | | 249 | |
2.600% Series U, due 2026 | 400 | | | 397 | | | 397 | |
6.750% Series P, due 2037 | 252 | | | 254 | | | 256 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.850% Pollution Control Series 2016B, due 2029(2) | 30 | | | 30 | | | 29 | |
3.000% Gas and Water Series 2016B, due 2036(3) | 60 | | | 60 | | | 61 | |
0.625% Water Facilities Series 2016C, due 2036(2) | 30 | | | 30 | | | 30 | |
2.050% Water Facilities Series 2016D, due 2036(2) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016E, due 2036(2) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016F, due 2036(2) | 75 | | | 75 | | | 74 | |
1.850% Water Facilities Series 2016G, due 2036(2) | 20 | | | 20 | | | 20 | |
Total Sierra Pacific | 1,167 | | | 1,165 | | | 1,166 | |
Total NV Energy | $ | 3,701 | | | $ | 3,675 | | | $ | 3,673 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
NV Energy - | | | | | |
6.250% Senior Notes, due 2020 | $ | 315 |
| | $ | 330 |
| | $ | 337 |
|
| | | | | |
Nevada Power: | | | | | |
General and refunding mortgage securities: | | | | | |
6.500% Series O, due 2018 | — |
| | — |
| | 324 |
|
6.500% Series S, due 2018 | — |
| | — |
| | 499 |
|
7.125% Series V, due 2019 | 500 |
| | 500 |
| | 499 |
|
2.750%, Series BB, due 2020 | 575 |
| | 574 |
| | — |
|
6.650% Series N, due 2036 | 367 |
| | 360 |
| | 359 |
|
6.750% Series R, due 2037 | 349 |
| | 348 |
| | 348 |
|
5.375% Series X, due 2040 | 250 |
| | 248 |
| | 248 |
|
5.450% Series Y, due 2041 | 250 |
| | 244 |
| | 244 |
|
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.800% Pollution Control Bonds Series 2017A, due 2032(1) | 40 |
| | 40 |
| | 40 |
|
1.600% Pollution Control Bonds Series 2017, due 2036(1) | 40 |
| | 39 |
| | 39 |
|
1.600% Pollution Control Bonds Series 2017B, due 2039(1) | 13 |
| | 13 |
| | 13 |
|
Capital and financial lease obligations - 2.750% to 11.600%, due through 2054 | 463 |
| | 463 |
| | 475 |
|
Total Nevada Power | 2,847 |
| | 2,829 |
| | 3,088 |
|
| | | | | |
Sierra Pacific: | | | | | |
General and refunding mortgage securities: | | | | | |
3.375% Series T, due 2023 | 250 |
| | 249 |
| | 249 |
|
2.600% Series U, due 2026 | 400 |
| | 396 |
| | 396 |
|
6.750% Series P, due 2037 | 252 |
| | 256 |
| | 256 |
|
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.250% Pollution Control Series 2016A, due 2029(2) | 20 |
| | 20 |
| | 20 |
|
1.500% Gas Facilities Series 2016A, due 2031(2) | 59 |
| | 58 |
| | 58 |
|
3.000% Gas and Water Series 2016B, due 2036(3) | 60 |
| | 62 |
| | 63 |
|
Variable-rate series (2018 - 1.750% to 1.820%, 2017 - 1.690% to 1.840%): | | | | | |
Water Facilities Series 2016C, due 2036 | 30 |
| | 30 |
| | 30 |
|
Water Facilities Series 2016D, due 2036 | 25 |
| | 25 |
| | 25 |
|
Water Facilities Series 2016E, due 2036 | 25 |
| | 25 |
| | 25 |
|
Capital and financial lease obligations - 2.700% to 10.297%, due through 2054 | 38 |
| | 38 |
| | 34 |
|
Total Sierra Pacific | 1,159 |
| | 1,159 |
| | 1,156 |
|
Total NV Energy | $ | 4,321 |
| | $ | 4,318 |
| | $ | 4,581 |
|
(1) Bonds were purchased by Nevada Power in May 2020 and re-offered at a fixed interest rate. Subject to mandatory purchase by Nevada Power in May 2020March 2023 at which date the interest rate may be adjusted from time to time.adjusted.
(2) Subject to mandatory purchase by Sierra Pacific in June 2019April 2022 at which date the interest rate may be adjusted from time to time.adjusted.
(3) Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted from time to time.adjusted.
In January 2019, Nevada Power issued $500 million of its 3.70% General and Refunding Mortgage Notes, Series CC, due May 2029.
The issuance of General and Refunding Mortgage Securities by the Nevada Utilities are subject to PUCN approval and are limited by available property and other provisions of the mortgage indentures for each of Nevada Power and Sierra Pacific. As of December 31, 2018,2021, approximately $8.5$9 billion of Nevada Power's and $4.1$5 billion of Sierra Pacific's (based on original cost) property was subject to the liens of the mortgages.
Northern Powergrid
Northern Powergrid and its subsidiaries' long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value(1) | | 2021 | | 2020 |
| | | | | |
4.133% European Investment Bank loans, due 2022 | $ | 204 | | | $ | 204 | | | $ | 206 | |
7.25% Bonds, due 2022 | 271 | | | 269 | | | 277 | |
2.50% Bonds, due 2025 | 203 | | | 202 | | | 203 | |
2.073% European Investment Bank loan, due 2025 | 67 | | | 69 | | | 70 | |
2.564% European Investment Bank loans, due 2027 | 338 | | | 337 | | | 340 | |
7.25% Bonds, due 2028 | 251 | | | 254 | | | 257 | |
4.375% Bonds, due 2032 | 203 | | | 200 | | | 202 | |
5.125% Bonds, due 2035 | 271 | | | 268 | | | 270 | |
5.125% Bonds, due 2035 | 203 | | | 201 | | | 203 | |
2.750% Bonds, due 2049 | 203 | | | 200 | | | 202 | |
2.250% Bonds, due 2059 | 406 | | | 398 | | | 402 | |
1.875% Bonds, due 2062 | 406 | | | 398 | | | 403 | |
Variable-rate loan, due 2026(2) | — | | | — | | | 183 | |
Variable-rate loan, due 2026(3) | — | | | — | | | 41 | |
Variable-rate loan, due 2026(4) | 295 | | | 287 | | | — | |
Total Northern Powergrid | $ | 3,321 | | | $ | 3,287 | | | $ | 3,259 | |
(1)The par values for these debt instruments are denominated in sterling.
(2)The Company had entered into an interest rate swap that fixed the interest rate on 89% of the outstanding debt. The variable interest rate as of December 31, 2020 was 2.03% (including 2.0% margin) and the fixed interest rate was 3.07% (including 2.0% margin), resulting in a blended rate of 2.96%.
(3)The variable interest rate as of December 31, 2020 was 2.02% (including 2.0% margin).
(4)Amortizes semiannually and the Company has entered into an interest rate swap that fixes the interest rate on 80% of the outstanding debt. The variable interest rate as of December 31, 2021 was 1.73% (including 1.55% margin) and the fixed interest rate was 2.45% (including 1.55% margin), resulting in a blended rate of 2.30%.
|
| | | | | | | | | | | |
| Par Value(1) | | 2018 | | 2017 |
| | | | | |
8.875% Bonds, due 2020 | $ | 128 |
| | $ | 133 |
| | $ | 144 |
|
9.25% Bonds, due 2020 | 255 |
| | 260 |
| | 279 |
|
3.901% to 4.586% European Investment Bank loans, due 2018 to 2022 | 294 |
| | 293 |
| | 366 |
|
7.25% Bonds, due 2022 | 255 |
| | 262 |
| | 279 |
|
2.50% Bonds due 2025 | 191 |
| | 189 |
| | 200 |
|
2.073% European Investment Bank loan, due 2025 | 64 |
| | 65 |
| | 69 |
|
2.564% European Investment Bank loans, due 2027 | 319 |
| | 318 |
| | 336 |
|
7.25% Bonds, due 2028 | 237 |
| | 241 |
| | 256 |
|
4.375% Bonds, due 2032 | 191 |
| | 188 |
| | 199 |
|
5.125% Bonds, due 2035 | 255 |
| | 252 |
| | 267 |
|
5.125% Bonds, due 2035 | 191 |
| | 189 |
| | 200 |
|
Variable-rate bond, due 2026(2) | 241 |
| | 236 |
| | 210 |
|
Total Northern Powergrid | $ | 2,621 |
| | $ | 2,626 |
| | $ | 2,805 |
|
| |
(1) | The par values for these debt instruments are denominated in sterling. |
| |
(2) | Amortizes semiannually and the Company has entered into an interest rate swap that fixes the interest rate on 85% of the outstanding debt. The variable interest rate as of December 31, 2018 was 2.66% while the fixed interest rate was 2.82%. |
BHE Pipeline Group
BHE Pipeline Group's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
Eastern Energy Gas: | | | | | |
Variable-rate Senior Notes, due 2021(1) | $ | — | | | $ | — | | | $ | 500 | |
2.875% Senior Notes, due 2023 | 250 | | | 250 | | | 249 | |
3.55% Senior Notes, due 2023 | 400 | | | 399 | | | 399 | |
2.50% Senior Notes, due 2024 | 600 | | | 597 | | | 596 | |
3.60% Senior Notes, due 2024 | 339 | | | 338 | | | 448 | |
3.32% Senior Notes, due 2026 (€250)(2) | 284 | | | 283 | | | 304 | |
3.00% Senior Notes, due 2029 | 174 | | | 173 | | | 594 | |
3.80% Senior Notes, due 2031 | 150 | | | 150 | | | 150 | |
4.80% Senior Notes, due 2043 | 54 | | | 53 | | | 395 | |
4.60% Senior Notes, due 2044 | 56 | | | 56 | | | 493 | |
3.90% Senior Notes, due 2049 | 27 | | | 26 | | | 297 | |
| | | | | |
EGTS: | | | | | |
3.60% Senior Notes, due 2024 | 111 | | | 110 | | | — | |
3.00% Senior Notes, due 2029 | 426 | | | 422 | | | — | |
4.80% Senior Notes, due 2043 | 346 | | | 341 | | | — | |
4.60% Senior Notes, due 2044 | 444 | | | 437 | | | — | |
3.90% Senior Notes, due 2049 | 273 | | | 271 | | | — | |
Total Eastern Energy Gas | 3,934 | | | 3,906 | | | 4,425 | |
Fair value adjustments | — | | | 430 | | | 493 | |
Total Eastern Energy Gas, net of fair value adjustments | 3,934 | | | 4,336 | | | 4,918 | |
| | | | | |
Northern Natural Gas: | | | | | |
4.25% Senior Notes, due 2021 | — | | | — | | | 200 | |
5.80% Senior Bonds, due 2037 | 150 | | | 149 | | | 149 | |
4.10% Senior Bonds, due 2042 | 250 | | | 248 | | | 248 | |
4.30% Senior Bonds, due 2049 | 650 | | | 651 | | | 650 | |
3.40% Senior Bonds, due 2051 | 550 | | | 540 | | | — | |
Total Northern Natural Gas | 1,600 | | | 1,588 | | | 1,247 | |
Total BHE Pipeline Group | $ | 5,534 | | | $ | 5,924 | | | $ | 6,165 | |
(1) The senior notes had variable interest rates based on LIBOR plus an applicable margin. Eastern Energy Gas entered into an interest rate swap that fixed the interest rate on 100% of the notes. The fixed interest rate as of December 31, 2020 was 3.46% including a 0.60% margin.
(2) The senior notes are denominated in Euros with an outstanding principal balance of €250 million and a fixed interest rate of 1.45%. Eastern Energy Gas has entered into cross currency swaps that fix USD payments for 100% of the notes. The fixed USD outstanding principal when combined with the swaps is $280 million, with fixed interest rates at both December 31, 2021 and 2020 that averaged 3.32%.
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
Northern Natural Gas: | | | | | |
5.75% Senior Notes, due 2018 | $ | — |
| | $ | — |
| | $ | 200 |
|
4.25% Senior Notes, due 2021 | 200 |
| | 199 |
| | 199 |
|
5.80% Senior Bonds, due 2037 | 150 |
| | 149 |
| | 149 |
|
4.10% Senior Bonds, due 2042 | 250 |
| | 248 |
| | 248 |
|
4.30% Senior Bonds, due 2049 | 450 |
| | 446 |
| | — |
|
Total BHE Pipeline Group | $ | 1,050 |
| | $ | 1,042 |
| | $ | 796 |
|
BHE Transmission
BHE Transmission's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value(1) | | 2021 | | 2020 |
AltaLink Investments, L.P.: | | | | | |
Series 15-1 Senior Bonds, 2.244%, due 2022 | $ | 158 | | | $ | 158 | | | $ | 157 | |
Total AltaLink Investments, L.P. | 158 | | | 158 | | | 157 | |
| | | | | |
AltaLink, L.P.: | | | | | |
Series 2012-2 Notes, 2.978%, due 2022 | 218 | | | 218 | | | 216 | |
Series 2013-4 Notes, 3.668%, due 2023 | 396 | | | 395 | | | 392 | |
Series 2014-1 Notes, 3.399%, due 2024 | 277 | | | 277 | | | 275 | |
Series 2016-1 Notes, 2.747%, due 2026 | 277 | | | 276 | | | 274 | |
Series 2020-1 Notes, 1.509%, due 2030 | 178 | | | 177 | | | 175 | |
Series 2006-1 Notes, 5.249%, due 2036 | 119 | | | 118 | | | 118 | |
Series 2010-1 Notes, 5.381%, due 2040 | 99 | | | 99 | | | 98 | |
Series 2010-2 Notes, 4.872%, due 2040 | 119 | | | 118 | | | 117 | |
Series 2011-1 Notes, 4.462%, due 2041 | 218 | | | 217 | | | 215 | |
Series 2012-1 Notes, 3.990%, due 2042 | 415 | | | 410 | | | 407 | |
Series 2013-3 Notes, 4.922%, due 2043 | 277 | | | 276 | | | 274 | |
Series 2014-3 Notes, 4.054%, due 2044 | 233 | | | 232 | | | 230 | |
Series 2015-1 Notes, 4.090%, due 2045 | 277 | | | 275 | | | 273 | |
Series 2016-2 Notes, 3.717%, due 2046 | 356 | | | 354 | | | 351 | |
Series 2013-1 Notes, 4.446%, due 2053 | 198 | | | 197 | | | 196 | |
Series 2014-2 Notes, 4.274%, due 2064 | 103 | | | 103 | | | 102 | |
Total AltaLink, L.P. | 3,760 | | | 3,742 | | | 3,713 | |
| | | | | |
Other: | | | | | |
Construction Loan, 5.620%, due 2024 | 6 | | | 6 | | | 7 | |
| | | | | |
Total BHE Transmission | $ | 3,924 | | | $ | 3,906 | | | $ | 3,877 | |
(1)The par values for these debt instruments are denominated in Canadian dollars.
|
| | | | | | | | | | | |
| Par Value(1) | | 2018 | | 2017 |
AltaLink Investments, L.P.: | | | | | |
Series 12-1 Senior Bonds, 3.674%, due 2019 | $ | 147 |
| | $ | 148 |
| | $ | 162 |
|
Series 13-1 Senior Bonds, 3.265%, due 2020 | 147 |
| | 148 |
| | 161 |
|
Series 15-1 Senior Bonds, 2.244%, due 2022 | 147 |
| | 146 |
| | 158 |
|
Total AltaLink Investments, L.P. | 441 |
| | 442 |
| | 481 |
|
| | | | | |
AltaLink, L.P.: | | | | | |
Series 2008-1 Notes, 5.243%, due 2018 | — |
| | — |
| | 159 |
|
Series 2013-2 Notes, 3.621%, due 2020 | 92 |
| | 92 |
| | 99 |
|
Series 2012-2 Notes, 2.978%, due 2022 | 202 |
| | 201 |
| | 218 |
|
Series 2013-4 Notes, 3.668%, due 2023 | 366 |
| | 366 |
| | 397 |
|
Series 2014-1 Notes, 3.399%, due 2024 | 256 |
| | 256 |
| | 278 |
|
Series 2016-1 Notes, 2.747%, due 2026 | 256 |
| | 255 |
| | 277 |
|
Series 2006-1 Notes, 5.249%, due 2036 | 110 |
| | 109 |
| | 119 |
|
Series 2010-1 Notes, 5.381%, due 2040 | 92 |
| | 91 |
| | 99 |
|
Series 2010-2 Notes, 4.872%, due 2040 | 110 |
| | 109 |
| | 119 |
|
Series 2011-1 Notes, 4.462%, due 2041 | 202 |
| | 201 |
| | 218 |
|
Series 2012-1 Notes, 3.990%, due 2042 | 385 |
| | 380 |
| | 412 |
|
Series 2013-3 Notes, 4.922%, due 2043 | 256 |
| | 256 |
| | 278 |
|
Series 2014-3 Notes, 4.054%, due 2044 | 216 |
| | 215 |
| | 233 |
|
Series 2015-1 Notes, 4.090%, due 2045 | 256 |
| | 255 |
| | 277 |
|
Series 2016-2 Notes, 3.717%, due 2046 | 330 |
| | 328 |
| | 356 |
|
Series 2013-1 Notes, 4.446%, due 2053 | 183 |
| | 183 |
| | 198 |
|
Series 2014-2 Notes, 4.274%, due 2064 | 95 |
| | 95 |
| | 103 |
|
Total AltaLink, L.P. | 3,407 |
| | 3,392 |
| | 3,840 |
|
| | | | | |
Other: | | | | | |
Construction Loan, 5.660%, due 2020 | 8 |
| | 8 |
| | 13 |
|
| | | | | |
Total BHE Transmission | $ | 3,856 |
| | $ | 3,842 |
| | $ | 4,334 |
|
| |
(1) | The par values for these debt instruments are denominated in Canadian dollars. |
BHE Renewables
BHE Renewables' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
Fixed-rate(1): | | | | | |
Bishop Hill Holdings Senior Notes, 5.125%, due 2032 | $ | 62 | | | $ | 62 | | | $ | 69 | |
Solar Star Funding Senior Notes, 3.950%, due 2035 | 258 | | | 256 | | | 269 | |
Solar Star Funding Senior Notes, 5.375%, due 2035 | 826 | | | 819 | | | 853 | |
Grande Prairie Wind Senior Notes, 3.860%, due 2037 | 299 | | | 297 | | | 327 | |
Topaz Solar Farms Senior Notes, 5.750%, due 2039 | 606 | | | 600 | | | 631 | |
Topaz Solar Farms Senior Notes, 4.875%, due 2039 | 172 | | | 170 | | | 180 | |
Alamo 6 Senior Notes, 4.170%, due 2042 | 199 | | | 197 | | | 205 | |
Other | 5 | | | 5 | | | 8 | |
Variable-rate(1): | | | | | |
TX Jumbo Road Term Loan, due 2025(2) | 119 | | | 117 | | | 138 | |
Marshall Wind Term Loan, due 2026(2) | 64 | | | 63 | | | 69 | |
Flat Top Wind I Term Loan, due 2028(2) | 113 | | | 113 | | | — | |
Pinyon Pines I and II Term Loans, due 2034(2) | 350 | | | 344 | | | 367 | |
Total BHE Renewables | $ | 3,073 | | | $ | 3,043 | | | $ | 3,116 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
Fixed-rate(1): | | | | | |
Bishop Hill Holdings Senior Notes, 5.125%, due 2032 | 85 |
| | 84 |
| | 93 |
|
Solar Star Funding Senior Notes, 3.950%, due 2035 | 295 |
| | 292 |
| | 310 |
|
Solar Star Funding Senior Notes, 5.375%, due 2035 | 924 |
| | 915 |
| | 965 |
|
Grande Prairie Wind Senior Notes, 3.860%, due 2037 | 396 |
| | 392 |
| | 404 |
|
Topaz Solar Farms Senior Notes, 5.750%, due 2039 | 718 |
| | 709 |
| | 745 |
|
Topaz Solar Farms Senior Notes, 4.875%, due 2039 | 207 |
| | 205 |
| | 217 |
|
Alamo 6 Senior Notes, 4.170%, due 2042 | 224 |
| | 221 |
| | 229 |
|
Other | 16 |
| | 16 |
| | 19 |
|
Variable-rate(1): | | | | | |
Pinyon Pines I and II Term Loans, due 2019(2) | 310 |
| | 310 |
| | 333 |
|
TX Jumbo Road Term Loan, due 2025(2) | 180 |
| | 176 |
| | 193 |
|
Marshall Wind Term Loan, due 2026(2) | 83 |
| | 81 |
| | 86 |
|
Total BHE Renewables | $ | 3,438 |
| | $ | 3,401 |
| | $ | 3,594 |
|
| |
(1) | Amortizes quarterly or semiannually. |
| |
(2) | The term loans have variable interest rates based on LIBOR plus a margin that varies during the terms of the agreements. The Company has entered into interest rate swaps that fix the interest rate on 75% of the Pinyon Pines outstanding debt and 100% of the TX Jumbo Road and Marshall Wind outstanding debt. The variable interest rate as of December 31, 2018 and 2017 was 4.55% and 3.32%, respectively, while the fixed interest rates as of December 31, 2018 and 2017 ranged from 3.21% to 3.63%.
|
(1)Amortizes quarterly or semiannually.
HomeServices(2)The term loans have variable interest rates based on LIBOR or Secured Overnight Financing Rate plus a margin that varies during the terms of the agreements. The Company has entered into interest rate swaps that fix the interest rate on 100% of the TX Jumbo Road, Marshall Wind and Pinyon Pines outstanding debt. The fixed interest rates as of December 31, 2021 and 2020 ranged from 3.21% to 3.88%. The variable interest rate on the Flat Top Wind I outstanding debt was 6.34% as of December 31, 2021.
HomeServices
HomeServices' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
Variable-rate: | | | | | |
Variable-rate term loan (2021 - 0.950%, 2020 - 1.147%), due 2026(1) | $ | 148 | | | $ | 148 | | | $ | 186 | |
(1)Term loan amortizes quarterly and variable-rate resets monthly.
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
Variable-rate(1): | | | | | |
Variable-rate term loan (2018 - 4.022%, 2017 - 2.819%), due 2022 | $ | 233 |
| | $ | 233 |
| | $ | 247 |
|
Annual Repayments of Long-Term Debt
The annual repayments of BHE and subsidiary debt for the years beginning January 1, 20192022 and thereafter, excluding fair value adjustments and unamortized premiums, discounts and debt issuance costs, are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2027 and | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
| | | | | | | | | | | | | |
BHE senior notes | $ | — | | | $ | 900 | | | $ | — | | | $ | 1,650 | | | $ | — | | | $ | 10,551 | | | $ | 13,101 | |
BHE junior subordinated debentures | — | | | — | | | — | | | — | | | — | | | 100 | | | 100 | |
PacifiCorp | 155 | | | 449 | | | 592 | | | 301 | | | 100 | | | 7,200 | | | 8,797 | |
MidAmerican Funding | — | | | 316 | | | 537 | | | 15 | | | 2 | | | 7,177 | | | 8,047 | |
NV Energy | — | | | 250 | | | — | | | — | | | 400 | | | 3,051 | | | 3,701 | |
Northern Powergrid | 526 | | | 56 | | | 56 | | | 318 | | | 84 | | | 2,281 | | | 3,321 | |
BHE Pipeline Group | — | | | 650 | | | 1,050 | | | — | | | 284 | | | 3,550 | | | 5,534 | |
BHE Transmission | 377 | | | 397 | | | 282 | | | — | | | 277 | | | 2,591 | | | 3,924 | |
BHE Renewables | 199 | | | 200 | | | 210 | | | 241 | | | 218 | | | 2,005 | | | 3,073 | |
HomeServices | 8 | | | 7 | | | 9 | | | 15 | | | 109 | | | — | | | 148 | |
Totals | $ | 1,265 | | | $ | 3,225 | | | $ | 2,736 | | | $ | 2,540 | | | $ | 1,474 | | | $ | 38,506 | | | $ | 49,746 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2024 and | | |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
| | | | | | | | | | | | | |
BHE senior notes | $ | — |
| | $ | 350 |
| | $ | 450 |
| | $ | — |
| | $ | 900 |
| | $ | 6,951 |
| | $ | 8,651 |
|
BHE junior subordinated debentures | — |
| | — |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
|
PacifiCorp | 352 |
| | 40 |
| | 425 |
| | 606 |
| | 450 |
| | 5,203 |
| | 7,076 |
|
MidAmerican Funding | 500 |
| | 2 |
| | — |
| | 1 |
| | 315 |
| | 4,850 |
| | 5,668 |
|
NV Energy | 523 |
| | 913 |
| | 28 |
| | 29 |
| | 271 |
| | 2,557 |
| | 4,321 |
|
Northern Powergrid | 80 |
| | 462 |
| | 31 |
| | 479 |
| | 33 |
| | 1,536 |
| | 2,621 |
|
BHE Pipeline Group | — |
| | — |
| | 200 |
| | — |
| | — |
| | 850 |
| | 1,050 |
|
BHE Transmission | 148 |
| | 245 |
| | — |
| | 348 |
| | 367 |
| | 2,748 |
| | 3,856 |
|
BHE Renewables | 483 |
| | 168 |
| | 175 |
| | 172 |
| | 177 |
| | 2,263 |
| | 3,438 |
|
HomeServices | 20 |
| | 27 |
| | 33 |
| | 153 |
| | — |
| | — |
| | 233 |
|
Totals | $ | 2,106 |
| | $ | 2,207 |
| | $ | 1,342 |
| | $ | 1,788 |
| | $ | 2,513 |
| | $ | 27,058 |
| | $ | 37,014 |
|
(11)(12)Income Taxes
Tax Cuts and Jobs Act
The 2017 Tax Reform impacted many areas ofCompany's provision for income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, the one-time repatriation tax of foreign earnings and profits and limitationstaxes has been computed on bonus depreciation for utility property. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, in December 2017,stand-alone basis. Berkshire Hathaway includes the Company reduced deferred income tax liabilities $7,115 million. As it is probable the change in deferred taxes for the Company's regulated businesses will be passed back to customers through regulatory mechanisms, the Company increased net regulatory liabilities by $5,950 million. The reduction in deferred income tax liabilities also resulted in a decrease in deferred income tax expense of $1,150 million, mostly driven by the Company's non-regulated businesses, primarily BHE Renewables, BHE's investment in BYD Company Limitedits consolidated United States federal and HomeServices.
As a result of the 2017 Tax Reform, BHE's consolidated net income in 2017 increased by $516 million primarily due to benefits from reductions in deferred income tax liabilities of $1,150 million, partially offset by an accrual for the deemed repatriation of undistributed foreign earnings and profits totaling $419 million and equity earnings charges totaling $228 million mainly for amounts to be returned to the customers of equity investments in regulated entities.
In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. The Company recorded the impacts of the 2017 Tax Reform in December 2017 and believed all the impacts to be complete with the exception of the repatriation tax on foreign earnings and interpretations of the bonus depreciation rules. The Company determined the amounts recorded and the interpretations relating to these two items to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. The Company believed the estimates for the repatriation tax to be reasonable, however, additional time was required to validate the inputs to the foreign earnings and profits calculation, the basis on which the repatriation tax is determined and additional guidance was required to determineIowa state income tax implications. The Company also believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, the Company finalized its provisional amounts resulting in a $134 million reduction to the repatriation tax liability estimate, based on further analysis of the earnings and profits completed during 2018 and additional guidance from certain states. In addition, the Company recorded a current tax benefit and deferred tax expense of $68 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reformreturns and the naturemajority of the Company's regulated businesses,United States federal income tax is remitted to or received from Berkshire Hathaway. As of December 31, 2021, the Company reduced the associated deferredhad a current income tax liabilities $27receivable from Berkshire Hathaway for federal income tax of $324 million and increased regulatory liabilities by the same amount.
Iowa Senate File 2417
In May 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% and eliminates corporate federal deductibility, both for tax years starting in 2021. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of Iowa Senate File 2417, the Company reduced deferred income tax liabilities $61 million and decreased deferred income tax expense by $2 million. As it is probable the change in deferred taxes for the Company's regulated businesses will be passed back to customers through regulatory mechanisms, the Company increased net regulatory liabilities by $59 million. In connection with Iowa Senate File 2417, the Company determined it was more appropriate to present the deferred income tax assets of $609 million associated with the state of Iowa net operating loss carryforward as a long-term income tax receivable from Berkshire Hathaway, reflected as a component of BHE's shareholders' equity.equity, of $744 million for Iowa state income tax. As of December 31, 2020, the Company does not currently expect to receive the majority of thehad a current income tax amountsreceivable from Berkshire Hathaway related to the state of Iowa prior to the 2021 effective date, the Company remeasured the long-termfor federal income tax receivable with Berkshire Hathaway at the enactment dateof $13 million and recorded a decrease to the long-term income tax receivable from Berkshire Hathaway, reflected as a component of $115 million. Subsequent toBHE's shareholders' equity, of $658 million for Iowa state income tax. Additionally, for the remeasurement date, the Company amended the tax sharing agreement with Berkshire Hathawayyears ended December 31, 2021 and received $90 million in 2019 related to previously used state of Iowa net operating loss carryforwards thereby increasing the current income tax receivable from Berkshire Hathaway and decreasing the long-term income tax receivable by the same amount. Additionally, during the year2020 the Company generated $53$100 million of stateand $138 million, respectively, of Iowa state net operating losses which will bewere carried forward and will increaseincreased the long-term income tax receivable from Berkshire Hathaway.
The BHE GT&S acquisition on November 1, 2020 was treated as a deemed asset acquisition for federal and state income tax purposes due to Berkshire Hathaway and DEI making tax elections under Internal Revenue Code ("IRC") §338(h)(10) for all C-corporations acquired, the intent on making or having in place IRC §754 elections for any partnership interests purchased, and due to all single member LLCs acquired being treated as disregarded entities for income tax purposes. All deferred taxes at BHE GT&S were reset to reflect book and tax basis differences as of November 1, 2020. The primary deferred tax items recorded by the Company include long-term debt, pension and other postretirement liabilities, and intangible assets. Since the BHE GT&S acquisition is deemed an asset acquisition for federal and state income tax purposes, all of the approximately $0.9 billion of tax goodwill is amortizable over 15 years. At the acquisition date there is no deferred tax liability recorded for the difference between book goodwill of approximately $1.7 billion versus the tax goodwill of approximately $0.9 billion, due to the inability to record a deferred tax liability when book goodwill exceeds tax goodwill.
Income tax (benefit) expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Current: | | | | | |
Federal | $ | (1,701) | | | $ | (1,537) | | | $ | (956) | |
State | (177) | | | (121) | | | (13) | |
Foreign | 100 | | | 86 | | | 81 | |
| (1,778) | | | (1,572) | | | (888) | |
Deferred: | | | | | |
Federal | 1,037 | | | 1,438 | | | 431 | |
State | (476) | | | 424 | | | (127) | |
Foreign | 89 | | | 21 | | | (8) | |
| 650 | | | 1,883 | | | 296 | |
| | | | | |
Investment tax credits | (4) | | | (3) | | | (6) | |
Total | $ | (1,132) | | | $ | 308 | | | $ | (598) | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Current: | | | | | |
Federal | $ | (686 | ) | | $ | (653 | ) | | $ | (743 | ) |
State | (9 | ) | | (3 | ) | | 1 |
|
Foreign | 104 |
| | 83 |
| | 55 |
|
| (591 | ) | | (573 | ) | | (687 | ) |
Deferred: | | | | | |
Federal | 165 |
| | (76 | ) | | 1,164 |
|
State | (131 | ) | | 100 |
| | (59 | ) |
Foreign | (20 | ) | | 2 |
| | (7 | ) |
| 14 |
| | 26 |
| | 1,098 |
|
| | | | | |
Investment tax credits | (6 | ) | | (7 | ) | | (8 | ) |
Total | $ | (583 | ) | | $ | (554 | ) | | $ | 403 |
|
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (27) | | | (16) | | | (32) | |
Effects of ratemaking | (4) | | | (3) | | | (6) | |
State income tax, net of federal income tax benefit | (10) | | | 3 | | | (5) | |
Non-controlling interest | (2) | | | — | | | — | |
Income tax effect of foreign income | 1 | | | — | | | (2) | |
| | | | | |
Other, net | — | | | (1) | | | (1) | |
Effective income tax rate | (21) | % | | 4 | % | | (25) | % |
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
Income tax credits | (30 | ) | | (20 | ) | | (14 | ) |
Effects of ratemaking | (8 | ) | | (1 | ) | | — |
|
State income tax, net of federal income tax benefit | (6 | ) | | 3 |
| | (1 | ) |
Effects of tax rate change and repatriation tax | (4 | ) | | (31 | ) | | — |
|
Income tax effect of foreign income | (3 | ) | | (5 | ) | | (6 | ) |
Equity income | 1 |
| | (2 | ) | | 2 |
|
Other, net | (1 | ) | | (1 | ) | | (2 | ) |
Effective income tax rate | (30 | )% | | (22 | )% | | 14 | % |
Effects of 2017 Tax Reform have been included in state income tax, net of federal income tax benefit, effects of tax rate change and repatriation tax and equity income.
Income tax credits relate primarily to production tax credits ("PTC") from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity production tax creditsPTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the years ended December 31, 2021, 2020 and 2019 totaled $1.4 billion, $1.2 billion, and $0.8 billion, respectively.
Income tax effect ofon foreign income includes, among other items, deferred income tax benefitscharges of $16$105 million and $35 million in 20162021 and 2020, respectively, related to the enactment of reductions in the United KingdomKingdom's corporate income tax rate. In September 2016, the corporate income taxThe United Kingdom's rate is scheduled to increase from 19% to 25%, effective April 1, 2023, through legislation enacted in June 2021. The United Kingdom's rate was reducedscheduled to decrease from 18%19% to 17% effective April 1, 2020; however, the rate was maintained at 19% through amended legislation enacted in July 2020.
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and substantially all of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. As of December 31, 2018, the Company had a current income tax receivable from Berkshire Hathaway of $90 million and a long-term income tax receivable from Berkshire Hathaway, reflected as a component of BHE's shareholders' equity, of $457 million for Iowa state income tax. As of December 31, 2017, the Company had a current income tax receivable from Berkshire Hathaway for federal income tax of $334 million.
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 1,349 | | | $ | 1,420 | |
Federal, state and foreign carryforwards | 820 | | | 677 | |
AROs | 304 | | | 304 | |
| | | |
| | | |
Other | 686 | | | 777 | |
Total deferred income tax assets | 3,159 | | | 3,178 | |
Valuation allowances | (164) | | | (204) | |
Total deferred income tax assets, net | 2,995 | | | 2,974 | |
| | | |
Deferred income tax liabilities: | | | |
Property-related items | (11,814) | | | (10,816) | |
Investments | (2,877) | | | (2,821) | |
Regulatory assets | (764) | | | (785) | |
Other | (478) | | | (327) | |
Total deferred income tax liabilities | (15,933) | | | (14,749) | |
Net deferred income tax liability | $ | (12,938) | | | $ | (11,775) | |
|
| | | | | | | |
| 2018 | | 2017 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 1,674 |
| | $ | 1,707 |
|
Federal, state and foreign carryforwards | 596 |
| | 1,118 |
|
AROs | 232 |
| | 223 |
|
Employee benefits | 68 |
| | 45 |
|
Other | 459 |
| | 450 |
|
Total deferred income tax assets | 3,029 |
| | 3,543 |
|
Valuation allowances | (137 | ) | | (126 | ) |
Total deferred income tax assets, net | 2,892 |
| | 3,417 |
|
| | | |
Deferred income tax liabilities: | | | |
Property-related items | (10,185 | ) | | (9,950 | ) |
Investments | (876 | ) | | (843 | ) |
Regulatory assets | (656 | ) | | (651 | ) |
Other | (222 | ) | | (215 | ) |
Total deferred income tax liabilities | (11,939 | ) | | (11,659 | ) |
Net deferred income tax liability | $ | (9,047 | ) | | $ | (8,242 | ) |
The following table provides the Company's net operating loss and tax credit carryforwards and expiration dates as of December 31, 20182021 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Federal | | State | | Foreign | | Total |
Net operating loss carryforwards(1) | $ | 297 | | | $ | 9,013 | | | $ | 900 | | | $ | 10,210 | |
Deferred income taxes on net operating loss carryforwards | 63 | | | 506 | | | 207 | | | 776 | |
Expiration dates | 2022 - indefinite | | 2022 - indefinite | | 2028 - 2041 | | |
| | | | | | | |
Tax credits | $ | 15 | | | $ | 29 | | | $ | — | | | $ | 44 | |
Expiration dates | 2023 - 2034 | | 2022 - indefinite | | | | |
|
| | | | | | | | | | | | | | | |
| Federal | | State | | Foreign | | Total |
Net operating loss carryforwards(1) | $ | 284 |
| | $ | 5,577 |
| | $ | 562 |
| | $ | 6,423 |
|
Deferred income taxes on net operating loss carryforwards | $ | 60 |
| | $ | 312 |
| | $ | 151 |
| | $ | 523 |
|
Expiration dates | 2023-2026 | | 2019-2038 | | 2035-2038 | |
|
|
| | | | | | | |
Tax credits | $ | 45 |
| | $ | 28 |
| | $ | — |
| | $ | 73 |
|
Expiration dates | 2023- indefinite | | 2019- indefinite | |
| |
|
| |
(1) | The federal net operating loss carryforwards relate principally to net operating loss carryforwards of subsidiaries that are tax residents in both the United States and the United Kingdom. The federal net operating loss carryforwards were generated prior to Berkshire Hathaway Inc.'s ownership and will begin to expire in 2023. |
(1)The federal net operating loss carryforwards relate principally to net operating loss carryforwards of subsidiaries that are tax residents in both the United States and the United Kingdom. The federal net operating loss carryforwards were generated prior to Berkshire Hathaway Inc.'s ownership and will begin to expire in 2022.
The United States Internal Revenue Service has closed or effectively settled its examination of the Company's income tax returns through December 31, 2011.2013. The statute of limitations for the Company's income tax returns have expired through December 31, 2009,2011, for California, Michigan, Minnesota, Montana, Nebraska, Oregon, Utah and Utah,Wisconsin, and through December 31, 2014,2017, except for the impact of any federal audit adjustments, for Connecticut, District of Columbia, Idaho, Illinois, Iowa, Kansas and Kansas.New York. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
A reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 153 | | | $ | 145 | |
Additions based on tax positions related to the current year | 24 | | | 19 | |
Additions for tax positions of prior years | 13 | | | 6 | |
Reductions based on tax positions related to the current year | (19) | | | (14) | |
Reductions for tax positions of prior years | (83) | | | (1) | |
Statute of limitations | — | | | (4) | |
Settlements | (1) | | | 1 | |
Interest and penalties | 10 | | | 1 | |
Ending balance | $ | 97 | | | $ | 153 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 181 |
| | $ | 128 |
|
Additions based on tax positions related to the current year | 4 |
| | 6 |
|
Additions for tax positions of prior years | 38 |
| | 70 |
|
Reductions for tax positions of prior years | (38 | ) | | (18 | ) |
Statute of limitations | 2 |
| | (4 | ) |
Settlements | (2 | ) | | (1 | ) |
Ending balance | $ | 185 |
| | $ | 181 |
|
As of December 31, 20182021 and 2017,2020, the Company had unrecognized tax benefits totaling $154$100 million and $158$141 million,, respectively, that if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.
(12)(13)Employee Benefit Plans
Defined Benefit Plans
Domestic Operations
PacifiCorp, MidAmerican Energy and NV Energy sponsor defined benefit pension plans that cover a majority of all employees of BHE and its domestic energy subsidiaries. These pension plans include noncontributory defined benefit pension plans, supplemental executive retirement plans ("SERP") and a restoration plan for certain executives of NV Energy.plans. PacifiCorp, MidAmerican Energy and NV Energy also provide certain postretirement healthcare and life insurance benefits through various plans to eligible retirees.
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Questar, exclusive of the Questar Pipeline Group (the "GT&S Transaction"). Defined benefit pension and postretirement benefits provided to the employees of BHE GT&S, which were part of the GT&S Transaction completed on November 1, 2020, are administered in the respective plans sponsored by MidAmerican Energy. Initial pension and postretirement plan liabilities of $81 million and $37 million, respectively, resulted from the GT&S Transaction.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is generally calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | 30 | | | $ | 17 | | | $ | 16 | | | $ | 12 | | | $ | 7 | | | $ | 8 | |
Interest cost | 78 | | | 93 | | | 111 | | | 19 | | | 21 | | | 27 | |
Expected return on plan assets | (134) | | | (140) | | | (154) | | | (22) | | | (34) | | | (40) | |
Settlement | 3 | | | — | | | — | | | — | | | — | | | — | |
Net amortization | 25 | | | 32 | | | 31 | | | (3) | | | (4) | | | (6) | |
Net periodic benefit cost (credit) | $ | 2 | | | $ | 2 | | | $ | 4 | | | $ | 6 | | | $ | (10) | | | $ | (11) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | |
Service cost | $ | 21 |
| | $ | 24 |
| | $ | 29 |
| | $ | 9 |
| | $ | 9 |
| | $ | 9 |
|
Interest cost | 105 |
| | 116 |
| | 126 |
| | 24 |
| | 29 |
| | 31 |
|
Expected return on plan assets | (164 | ) | | (160 | ) | | (160 | ) | | (41 | ) | | (40 | ) | | (41 | ) |
Settlement | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net amortization | 28 |
| | 25 |
| | 46 |
| | (13 | ) | | (14 | ) | | (12 | ) |
Net periodic benefit cost (credit) | $ | 11 |
| | $ | 5 |
| | $ | 41 |
| | $ | (21 | ) | | $ | (16 | ) | | $ | (13 | ) |
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 2,824 | | | $ | 2,656 | | | $ | 744 | | | $ | 742 | |
Employer contributions | 13 | | | 13 | | | 14 | | | 3 | |
Participant contributions | — | | | — | | | 9 | | | 8 | |
Actual return on plan assets | 234 | | | 373 | | | 53 | | | 40 | |
Settlement | (134) | | | — | | | — | | | — | |
Benefits paid | (142) | | | (218) | | | (51) | | | (49) | |
Plan assets at fair value, end of year | $ | 2,795 | | | $ | 2,824 | | | $ | 769 | | | $ | 744 | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 2,761 |
| | $ | 2,525 |
| | $ | 736 |
| | $ | 666 |
|
Employer contributions | 38 |
| | 64 |
| | 8 |
| | 5 |
|
Participant contributions | — |
| | — |
| | 8 |
| | 10 |
|
Actual return on plan assets | (147 | ) | | 390 |
| | (38 | ) | | 106 |
|
Settlement | (119 | ) | | (15 | ) | | — |
| | — |
|
Benefits paid | (137 | ) | | (203 | ) | | (50 | ) | | (51 | ) |
Plan assets at fair value, end of year | $ | 2,396 |
| | $ | 2,761 |
| | $ | 664 |
| | $ | 736 |
|
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 3,077 | | | $ | 2,878 | | | $ | 758 | | | $ | 673 | |
Service cost | 30 | | | 17 | | | 12 | | | 7 | |
Interest cost | 78 | | | 93 | | | 19 | | | 21 | |
Participant contributions | — | | | — | | | 9 | | | 8 | |
Actuarial (gain) loss | (132) | | | 226 | | | (35) | | | 61 | |
Amendment | — | | | — | | | 2 | | | — | |
Settlement | (134) | | | — | | | — | | | — | |
Acquisition | — | | | 81 | | | — | | | 37 | |
Benefits paid | (142) | | | (218) | | | (51) | | | (49) | |
Benefit obligation, end of year | $ | 2,777 | | | $ | 3,077 | | | $ | 714 | | | $ | 758 | |
Accumulated benefit obligation, end of year | $ | 2,713 | | | $ | 2,999 | | | | | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 3,006 |
| | $ | 2,952 |
| | $ | 721 |
| | $ | 734 |
|
Service cost | 21 |
| | 24 |
| | 9 |
| | 9 |
|
Interest cost | 105 |
| | 116 |
| | 24 |
| | 29 |
|
Participant contributions | — |
| | — |
| | 8 |
| | 10 |
|
Actuarial (gain) loss | (160 | ) | | 132 |
| | (40 | ) | | (10 | ) |
Amendment | 2 |
| | — |
| | — |
| | — |
|
Settlement | (119 | ) | | (15 | ) | | — |
| | — |
|
Benefits paid | (137 | ) | | (203 | ) | | (50 | ) | | (51 | ) |
Benefit obligation, end of year | $ | 2,718 |
| | $ | 3,006 |
| | $ | 672 |
| | $ | 721 |
|
Accumulated benefit obligation, end of year | $ | 2,709 |
| | $ | 2,988 |
| | | | |
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 2,795 | | | $ | 2,824 | | | $ | 769 | | | $ | 744 | |
Benefit obligation, end of year | 2,777 | | | 3,077 | | | 714 | | | 758 | |
Funded status | $ | 18 | | | $ | (253) | | | $ | 55 | | | $ | (14) | |
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 204 | | | $ | 43 | | | $ | 60 | | | $ | 20 | |
Other current liabilities | (13) | | | (13) | | | — | | | — | |
Other long-term liabilities | (173) | | | (283) | | | (5) | | | (34) | |
Amounts recognized | $ | 18 | | | $ | (253) | | | $ | 55 | | | $ | (14) | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 2,396 |
| | $ | 2,761 |
| | $ | 664 |
| | $ | 736 |
|
Benefit obligation, end of year | 2,718 |
| | 3,006 |
| | 672 |
| | 721 |
|
Funded status | $ | (322 | ) | | $ | (245 | ) | | $ | (8 | ) | | $ | 15 |
|
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 20 |
| | $ | 66 |
| | $ | 5 |
| | $ | 32 |
|
Other current liabilities | (13 | ) | | (14 | ) | | — |
| | — |
|
Other long-term liabilities | (329 | ) | | (297 | ) | | (13 | ) | | (17 | ) |
Amounts recognized | $ | (322 | ) | | $ | (245 | ) | | $ | (8 | ) | | $ | 15 |
|
The SERPs and restoration plan have no plan assets; however, the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERPs and restoration plan. The cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $256$343 million and $272$303 million as of December 31, 20182021 and 2017,2020, respectively. These assets are not included in the plan assets in the above table, but are reflected in noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets.
The fair value of plan assets, projected benefit obligation and accumulated benefit obligation for (1) pension and other postretirement benefit plans with a projected benefit obligation in excess of the fair value of plan assets and (2) pension plans with an accumulated benefit obligation in excess of the fair value of plan assets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Fair value of plan assets | $ | — | | | $ | 1,782 | | | $ | 137 | | | $ | 417 | |
| | | | | | | |
Projected benefit obligation | $ | 186 | | | $ | 2,069 | | | $ | 142 | | | $ | 451 | |
| | | | | | | |
Fair value of plan assets | $ | — | | | $ | 1,064 | | | | | |
| | | | | | | |
Accumulated benefit obligation | $ | 185 | | | $ | 1,341 | | | | | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Fair value of plan assets | $ | 1,752 |
| | $ | 2,016 |
| | $ | 417 |
| | $ | 126 |
|
| | | | | | | |
Projected benefit obligation | $ | 2,091 |
| | $ | 2,327 |
| | $ | 429 |
| | $ | 143 |
|
| | | | | | | |
Accumulated benefit obligation | $ | 2,085 |
| | $ | 2,316 |
| | | | |
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net loss (gain) | $ | 343 | | | $ | 612 | | | $ | (34) | | | $ | 34 | |
Prior service credit | (1) | | | (1) | | | (1) | | | (9) | |
Regulatory deferrals | 11 | | | 2 | | | 2 | | | 3 | |
Total | $ | 353 | | | $ | 613 | | | $ | (33) | | | $ | 28 | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Net loss | $ | 747 |
| | $ | 649 |
| | $ | 50 |
| | $ | 14 |
|
Prior service credit | — |
| | (3 | ) | | (22 | ) | | (37 | ) |
Regulatory deferrals | (1 | ) | | (4 | ) | | 7 |
| | 7 |
|
Total | $ | 746 |
| | $ | 642 |
| | $ | 35 |
| | $ | (16 | ) |
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 20182021 and 20172020 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | Regulatory | | Comprehensive | | |
| Asset | | Liability | | Loss | | Total |
Pension | | | | | | | |
Balance, December 31, 2019 | $ | 661 | | | $ | (33) | | | $ | 24 | | | $ | 652 | |
Net (gain) loss arising during the year | (30) | | | 13 | | | 10 | | | (7) | |
| | | | | | | |
| | | | | | | |
Net amortization | (31) | | | — | | | (1) | | | (32) | |
Total | (61) | | | 13 | | | 9 | | | (39) | |
Balance, December 31, 2020 | 600 | | | (20) | | | 33 | | | 613 | |
Net gain arising during the year | (177) | | | (44) | | | (10) | | | (231) | |
| | | | | | | |
Settlement | (9) | | | 5 | | | — | | | (4) | |
Net amortization | (24) | | | — | | | (1) | | | (25) | |
Total | (210) | | | (39) | | | (11) | | | (260) | |
Balance, December 31, 2021 | $ | 390 | | | $ | (59) | | | $ | 22 | | | $ | 353 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | Regulatory | | Comprehensive | | |
| Asset | | Liability | | Loss | | Total |
Other Postretirement | | | | | | | |
Balance, December 31, 2019 | $ | 4 | | | $ | (32) | | | $ | (3) | | | $ | (31) | |
Net loss arising during the year | 36 | | | 12 | | | 7 | | | 55 | |
| | | | | | | |
Net amortization | 7 | | | (3) | | | — | | | 4 | |
Total | 43 | | | 9 | | | 7 | | | 59 | |
Balance, December 31, 2020 | 47 | | | (23) | | | 4 | | | 28 | |
Net gain arising during the year | (40) | | | (22) | | | (3) | | | (65) | |
Net prior service cost arising during the year | 1 | | | — | | | — | | | 1 | |
Net amortization | 3 | | | — | | | — | | | 3 | |
Total | (36) | | | (22) | | | (3) | | | (61) | |
Balance, December 31, 2021 | $ | 11 | | | $ | (45) | | | $ | 1 | | | $ | (33) | |
|
| | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | Regulatory | | Comprehensive | | |
| Asset | | Liability | | Loss | | Total |
Pension | | | | | | | |
Balance, December 31, 2016 | $ | 761 |
| | $ | (13 | ) | | $ | 13 |
| | $ | 761 |
|
Net (gain) loss arising during the year | (68 | ) | | (29 | ) | | 3 |
| | (94 | ) |
Net amortization | (28 | ) | | (1 | ) | | 4 |
| | (25 | ) |
Total | (96 | ) | | (30 | ) | | 7 |
| | (119 | ) |
Balance, December 31, 2017 | 665 |
| | (43 | ) | | 20 |
| | 642 |
|
Net loss (gain) arising during the year | 114 |
| | 43 |
| | (6 | ) | | 151 |
|
Net prior service cost arising during the year | — |
| | — |
| | 2 |
| | 2 |
|
Settlement | (21 | ) | | — |
| | — |
| | (21 | ) |
Net amortization | (28 | ) | | — |
| | — |
| | (28 | ) |
Total | 65 |
| | 43 |
| | (4 | ) | | 104 |
|
Balance, December 31, 2018 | $ | 730 |
| | $ | — |
| | $ | 16 |
| | $ | 746 |
|
|
| | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | Regulatory | | Comprehensive | | |
| Asset | | Liability | | Loss | | Total |
Other Postretirement | | | | | | | |
Balance, December 31, 2016 | $ | 55 |
| | $ | (12 | ) | | $ | — |
| | $ | 43 |
|
Net gain arising during the year | (52 | ) | | (21 | ) | | — |
| | (73 | ) |
Net amortization | 7 |
| | 7 |
| | — |
| | 14 |
|
Total | (45 | ) | | (14 | ) | | — |
| | (59 | ) |
Balance, December 31, 2017 | 10 |
| | (26 | ) | | — |
| | (16 | ) |
Net gain arising during the year | 23 |
| | 14 |
| | 1 |
| | 38 |
|
Net amortization | 11 |
| | 2 |
| | — |
| | 13 |
|
Total | 34 |
| | 16 |
| | 1 |
| | 51 |
|
Balance, December 31, 2018 | $ | 44 |
| | $ | (10 | ) | | $ | 1 |
| | $ | 35 |
|
Plan Assumptions
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 2.98 | % | | 2.60 | % | | 3.32 | % | | 2.95 | % | | 2.59 | % | | 3.24 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.22 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.44 | % | | 2.94 | % | | N/A | | N/A | | N/A |
2021 | 2.45 | % | | 2.25 | % | | 2.94 | % | | N/A | | N/A | | N/A |
2022 | 2.56 | % | | 2.25 | % | | 3.02 | % | | N/A | | N/A | | N/A |
2023 | 2.56 | % | | 2.65 | % | | 3.02 | % | | N/A | | N/A | | N/A |
2024 and beyond | 2.83 | % | | 2.65 | % | | 3.02 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | | |
Discount rate | 2.60 | % | | 3.32 | % | | 4.25 | % | | 2.59 | % | | 3.24 | % | | 4.21 | % |
Expected return on plan assets | 5.39 | % | | 5.94 | % | | 6.48 | % | | 3.35 | % | | 5.42 | % | | 6.39 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A | | N/A | | N/A |
Interest crediting rate for cash balance plan | 2.45 | % | | 2.44 | % | | 3.22 | % | | N/A | | N/A | | N/A |
|
| | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 4.25 | % | | 3.60 | % | | 4.06 | % | | 4.21 | % | | 3.57 | % | | 4.01 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | NA |
| | NA |
| | NA |
|
Interest crediting rates for cash balance plan | | | | | | |
|
| |
|
| |
|
|
2016 | NA |
| | NA |
| | 2.57 | % | | NA |
| | NA |
| | NA |
|
2017 | NA |
| | 2.49 | % | | 2.57 | % | | NA |
| | NA |
| | NA |
|
2018 | 3.38 | % | | 3.06 | % | | 2.57 | % | | NA |
| | NA |
| | NA |
|
2019 | 3.54 | % | | 3.06 | % | | 3.01 | % | | NA |
| | NA |
| | NA |
|
2020 | 3.54 | % | | 2.72 | % | | 3.01 | % | | NA |
| | NA |
| | NA |
|
2021 | 3.56 | % | | 2.72 | % | | 3.01 | % | | NA |
| | NA |
| | NA |
|
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | | |
Discount rate | 3.60 | % | | 4.06 | % | | 4.43 | % | | 3.57 | % | | 4.01 | % | | 4.33 | % |
Expected return on plan assets | 6.36 | % | | 6.55 | % | | 6.78 | % | | 6.44 | % | | 6.73 | % | | 7.03 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | NA |
| | NA |
| | NA |
|
Interest crediting rate for cash balance plan | 3.38 | % | | 2.49 | % | | 2.57 | % | | NA |
| | NA |
| | NA |
|
In establishing its assumption as to the expected return on plan assets, the Company utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
| | | | | | | | | | | |
| 2021 | | 2020 |
Assumed healthcare cost trend rates as of December 31: | | | |
Healthcare cost trend rate assumed for next year | 6.00 | % | | 6.30 | % |
Rate that the cost trend rate gradually declines to | 5.00 | % | | 5.00 | % |
Year that the rate reaches the rate it is assumed to remain at | 2025 | | 2025 |
|
| | | | | |
| 2018 | | 2017 |
Assumed healthcare cost trend rates as of December 31: | | | |
Healthcare cost trend rate assumed for next year | 6.80 | % | | 7.10 | % |
Rate that the cost trend rate gradually declines to | 5.00 | % | | 5.00 | % |
Year that the rate reaches the rate it is assumed to remain at | 2025 | | 2025 |
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $13 million and $1$5 million, respectively, during 2019.2022. Funding to the established pension trusts is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code,IRC, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. The Company considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. The Company's funding policy forCompany evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plans is to generally contribute an amount equal to the net periodic benefit cost.plans.
The expected benefit payments to participants in the Company's pension and other postretirement benefit plans for 20192022 through 20232026 and for the five years thereafter are summarized below (in millions):
| | | | | | | | | | | |
| Projected Benefit |
| Payments |
| | | Other |
| Pension | | Postretirement |
| | | |
2022 | $ | 210 | | | $ | 54 | |
2023 | 203 | | | 54 | |
2024 | 195 | | | 54 | |
2025 | 193 | | | 53 | |
2026 | 193 | | | 51 | |
2027-2031 | 837 | | | 229 | |
|
| | | | | | | |
| Projected Benefit |
| Payments |
| | | Other |
| Pension | | Postretirement |
| | | |
2019 | $ | 221 |
| | $ | 53 |
|
2020 | 224 |
| | 57 |
|
2021 | 221 |
| | 55 |
|
2022 | 212 |
| | 54 |
|
2023 | 212 |
| | 53 |
|
2024-2028 | 958 |
| | 243 |
|
Plan Assets
Investment Policy and Asset Allocations
The Company's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by each plan's Pension and Employee Benefits Plans Administrativethe Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
The target allocations (percentage of plan assets) for the Company's pension and other postretirement benefit plan assets are as follows as of December 31, 2018:
| | | | | | | | | | | |
| | | Other |
| Pension | | Postretirement |
| % | | % |
PacifiCorp: | | | |
Debt securities(1) | 55-85 | | 70-80 |
Equity securities(1) | 25-35 | | 20-30 |
Limited partnership interests | 0-10 | | 0-1 |
| | | |
| | | |
MidAmerican Energy: | | | Other |
| Pension | | Postretirement |
| % | | % |
PacifiCorp: | | | |
Debt securities(1) | 30-43 | | 33-37 |
Equity securities(1)
| 48-65 | | 62-66 |
Limited partnership interests | 6-12 | | 1-3 |
| | | |
MidAmerican Energy: | | | |
Debt securities(1)
| 20-50 | | 25-45 |
Equity securities(1)
| 60-80 | | 45-8025-35 |
Real estate fundsEquity securities(1) | 2-820-40 | | —65-75 |
Other | 0-3 | | |
Other | 0-15 | | 0-5 |
| | | |
NV Energy: | | | |
Debt securities(1)
| 53-77 | | 40 |
Equity securities(1)
| 23-47 | | 60 |
| |
(1)NV Energy: | For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities. | | |
Debt securities(1) | 85-100 | | 67-88 |
Equity securities(1) | 0-15 | | 12-33 |
(1)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for the Company's defined benefit pension plans (in millions):
| | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | | | |
| Level 1 | | Level 2 | | | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | — | | | $ | 64 | | | | | $ | 64 | |
Debt securities: | | | | | | | |
United States government obligations | 142 | | | — | | | | | 142 | |
| | | | | | | |
Corporate obligations | — | | | 912 | | | | | 912 | |
Municipal obligations | — | | | 66 | | | | | 66 | |
Agency, asset and mortgage-backed obligations | — | | | 93 | | | | | 93 | |
Equity securities: | | | | | | | |
United States companies | 135 | | | — | | | | | 135 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 277 | | | $ | 1,135 | | | | | 1,412 | |
Investment funds(2) measured at net asset value | | | | | | | 1,349 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 34 | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 2,795 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | — | | | $ | 79 | | | | | $ | 79 | |
Debt securities: | | | | | | | |
United States government obligations | 52 | | | — | | | | | 52 | |
| | | | | | | |
Corporate obligations | — | | | 748 | | | | | 748 | |
Municipal obligations | — | | | 69 | | | | | 69 | |
| | | | | | | |
Equity securities: | | | | | | | |
United States companies | 224 | | | — | | | | | 224 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 276 | | | $ | 896 | | | | | 1,172 | |
Investment funds(2) measured at net asset value | | | | | | | 1,521 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 88 | |
Real estate funds measured at net asset value | | | | | | | 43 | |
Total assets measured at fair value | | | | | | | $ | 2,824 | |
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 54% and 46%, respectively, for 2021 and 69% and 31%, respectively, for 2020. Additionally, these funds are invested in United States and international securities of approximately 89% and 11%, respectively, for 2021 and 79% and 21%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
|
| | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Total |
As of December 31, 2018: | | | | | |
Cash equivalents | $ | 8 |
| | $ | 41 |
| | $ | 49 |
|
Debt securities: | | | | | |
United States government obligations | 160 |
| | — |
| | 160 |
|
International government obligations | — |
| | 5 |
| | 5 |
|
Corporate obligations | — |
| | 373 |
| | 373 |
|
Municipal obligations | — |
| | 29 |
| | 29 |
|
Agency, asset and mortgage-backed obligations | — |
| | 123 |
| | 123 |
|
Equity securities: | | | | | |
United States companies | 492 |
| | 1 |
| | 493 |
|
International companies | 108 |
| | — |
| | 108 |
|
Investment funds(2) | 119 |
| | — |
| | 119 |
|
Total assets in the fair value hierarchy | $ | 887 |
| | $ | 572 |
| | 1,459 |
|
Investment funds(2) measured at net asset value | | | | | 792 |
|
Limited partnership interests(3) measured at net asset value | | | | | 104 |
|
Real estate funds measured at net asset value | | | | | 41 |
|
Total assets measured at fair value | | | | | $ | 2,396 |
|
| | | | | |
As of December 31, 2017: | | | | | |
Cash equivalents | $ | 10 |
| | $ | 76 |
| | $ | 86 |
|
Debt securities: | | | | | |
United States government obligations | 218 |
| | — |
| | 218 |
|
Corporate obligations | — |
| | 350 |
| | 350 |
|
Municipal obligations | — |
| | 16 |
| | 16 |
|
Agency, asset and mortgage-backed obligations | — |
| | 110 |
| | 110 |
|
Equity securities: | | | | | |
United States companies | 622 |
| | — |
| | 622 |
|
International companies | 136 |
| | — |
| | 136 |
|
Investment funds(2) | 83 |
| | 20 |
| | 103 |
|
Total assets in the fair value hierarchy | $ | 1,069 |
| | $ | 572 |
| | 1,641 |
|
Investment funds(2) measured at net asset value | | | | | 1,019 |
|
Limited partnership interests(3) measured at net asset value | | | | | 63 |
|
Real estate funds measured at net asset value | | | | | 38 |
|
Total assets measured at fair value | | | | | $ | 2,761 |
|
| |
(1) | Refer to Note 14 for additional discussion regarding the three levels of the fair value hierarchy. |
| |
(2) | Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 59% and 41%, respectively, for 2018 and 62% and 38%, respectively, for 2017. Additionally, these funds are invested in United States and international securities of approximately 73% and 27%, respectively, for 2018 and 68% and 32%, respectively, for 2017.
|
| |
(3) | Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital. |
The following table presents the fair value of plan assets, by major category, for the Company's defined benefit other postretirement plans (in millions):
| | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | | | |
| Level 1 | | Level 2 | | | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | 12 | | | $ | 4 | | | | | $ | 16 | |
Debt securities: | | | | | | | |
United States government obligations | 27 | | | — | | | | | 27 | |
| | | | | | | |
Corporate obligations | — | | | 85 | | | | | 85 | |
Municipal obligations | — | | | 43 | | | | | 43 | |
Agency, asset and mortgage-backed obligations | — | | | 38 | | | | | 38 | |
Equity securities: | | | | | | | |
United States companies | 4 | | | — | | | | | 4 | |
| | | | | | | |
Investment funds(2) | 394 | | | — | | | | | 394 | |
| | | | | | | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 437 | | | $ | 170 | | | | | 607 | |
Investment funds(2) measured at net asset value | | | | | | | 161 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 1 | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 769 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | 20 | | | $ | 2 | | | | | $ | 22 | |
Debt securities: | | | | | | | |
United States government obligations | 15 | | | — | | | | | 15 | |
| | | | | | | |
Corporate obligations | — | | | 102 | | | | | 102 | |
Municipal obligations | — | | | 82 | | | | | 82 | |
Agency, asset and mortgage-backed obligations | — | | | 47 | | | | | 47 | |
Equity securities: | | | | | | | |
United States companies | 6 | | | — | | | | | 6 | |
| | | | | | | |
Investment funds(2) | 299 | | | — | | | | | 299 | |
| | | | | | | |
Total assets in the fair value hierarchy | $ | 340 | | | $ | 233 | | | | | 573 | |
Investment funds(2) measured at net asset value | | | | | | | 167 | |
Limited partnership interests(3) measured at net asset value | | | | | | | 4 | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 744 | |
|
| | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Total |
As of December 31, 2018: | | | | | |
Cash equivalents | $ | 10 |
| | $ | 2 |
| | $ | 12 |
|
Debt securities: | | | | | |
United States government obligations | 13 |
| | — |
| | 13 |
|
Corporate obligations | — |
| | 42 |
| | 42 |
|
Municipal obligations | — |
| | 45 |
| | 45 |
|
Agency, asset and mortgage-backed obligations | — |
| | 30 |
| | 30 |
|
Equity securities: | | | | | |
United States companies | 158 |
| | — |
| | 158 |
|
International companies | 6 |
| | — |
| | 6 |
|
Investment funds | 202 |
| | 1 |
| | 203 |
|
Total assets in the fair value hierarchy | $ | 389 |
| | $ | 120 |
| | 509 |
|
Investment funds measured at net asset value | | | | | 149 |
|
Limited partnership interests measured at net asset value | | | | | 6 |
|
Total assets measured at fair value | | | | | $ | 664 |
|
| | | | | |
As of December 31, 2017: | | | | | |
Cash equivalents | $ | 11 |
| | $ | 3 |
| | $ | 14 |
|
Debt securities: | | | | | |
United States government obligations | 20 |
| | — |
| | 20 |
|
Corporate obligations | — |
| | 36 |
| | 36 |
|
Municipal obligations | — |
| | 46 |
| | 46 |
|
Agency, asset and mortgage-backed obligations | — |
| | 29 |
| | 29 |
|
Equity securities: | | | | | |
United States companies | 185 |
| | — |
| | 185 |
|
International companies | 8 |
| | — |
| | 8 |
|
Investment funds(2) | 219 |
| | 1 |
| | 220 |
|
Total assets in the fair value hierarchy | $ | 443 |
| | $ | 115 |
| | 558 |
|
Investment funds(2) measured at net asset value | | | | | 174 |
|
Limited partnership interests(3) measured at net asset value | | | | | 4 |
|
Total assets measured at fair value | | | | | $ | 736 |
|
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
| |
(1) | Refer to Note 14 for additional discussion regarding the three levels of the fair value hierarchy. |
| |
(2) | Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 65% and 35%, respectively, for 2018 and 68% and 32%, respectively, for 2017. Additionally, these funds are invested in United States and international securities of approximately 79% and 21%, respectively, for 2018 and 73% and 27%, respectively, for 2017.
|
| |
(3) | Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital. |
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 55% and 45%, respectively, for 2021 and 40% and 60%, respectively, for 2020. Additionally, these funds are invested in United States and international securities of approximately 88% and 12%, respectively, for 2021 and 79% and 21%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Foreign Operations
Certain wholly-owned subsidiaries of Northern Powergrid participate in the Northern Powergrid group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the "UK Plan"), which provides pension and other related defined benefits, based on final pensionable pay, to the majority of the employees of Northern Powergrid. The UK Plan is closed to employees hired after July 23, 1997. Employees hired after that date are covered by a defined contribution plan sponsored by a wholly-owned subsidiary of Northern Powergrid.
Net Periodic Benefit Cost
For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreadingincluding the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
Net periodic benefit cost for the UK Plan included the following components for the years ended December 31 (in millions):
| | | 2018 | | 2017 | | 2016 |
| 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | 19 |
| | $ | 23 |
| | $ | 20 |
| Service cost | $ | 16 | | | $ | 16 | | | $ | 16 | |
Interest cost | 56 |
| | 58 |
| | 72 |
| Interest cost | 31 | | | 40 | | | 49 | |
Expected return on plan assets | (101 | ) | | (100 | ) | | (110 | ) | Expected return on plan assets | (111) | | | (101) | | | (100) | |
Settlement | 44 |
| | 31 |
| | — |
| Settlement | 10 | | | 17 | | | 26 | |
Net amortization | 45 |
| | 63 |
| | 44 |
| Net amortization | 55 | | | 43 | | | 46 | |
Net periodic benefit cost | $ | 63 |
| | $ | 75 |
| | $ | 26 |
| Net periodic benefit cost | $ | 1 | | | $ | 15 | | | $ | 37 | |
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Plan assets at fair value, beginning of year | $ | 2,334 | | | $ | 2,151 | |
Employer contributions | 28 | | | 56 | |
Participant contributions | 1 | | | 1 | |
Actual return on plan assets | 148 | | | 181 | |
Settlement | (51) | | | (63) | |
Benefits paid | (72) | | | (67) | |
Foreign currency exchange rate changes | (25) | | | 75 | |
Plan assets at fair value, end of year | $ | 2,363 | | | $ | 2,334 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Plan assets at fair value, beginning of year | $ | 2,368 |
| | $ | 2,169 |
|
Employer contributions | 60 |
| | 58 |
|
Participant contributions | 1 |
| | 1 |
|
Actual return on plan assets | (44 | ) | | 145 |
|
Settlement | (205 | ) | | (144 | ) |
Benefits paid | (71 | ) | | (68 | ) |
Foreign currency exchange rate changes | (120 | ) | | 207 |
|
Plan assets at fair value, end of year | $ | 1,989 |
| | $ | 2,368 |
|
The following table is a reconciliation of the benefit obligation for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Benefit obligation, beginning of year | $ | 2,205 | | | $ | 2,019 | |
Service cost | 16 | | | 16 | |
Interest cost | 31 | | | 40 | |
Participant contributions | 1 | | | 1 | |
Actuarial (gain) loss | (105) | | | 188 | |
Settlement | (51) | | | (63) | |
| | | |
Benefits paid | (72) | | | (67) | |
Foreign currency exchange rate changes | (22) | | | 71 | |
Benefit obligation, end of year | $ | 2,003 | | | $ | 2,205 | |
Accumulated benefit obligation, end of year | $ | 1,778 | | | $ | 1,963 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Benefit obligation, beginning of year | $ | 2,201 |
| | $ | 2,125 |
|
Service cost | 19 |
| | 23 |
|
Interest cost | 56 |
| | 58 |
|
Participant contributions | 1 |
| | 1 |
|
Actuarial gain | (87 | ) | | (4 | ) |
Settlement | (182 | ) | | (131 | ) |
Amendment | 8 |
| | — |
|
Benefits paid | (71 | ) | | (68 | ) |
Foreign currency exchange rate changes | (112 | ) | | 197 |
|
Benefit obligation, end of year | $ | 1,833 |
| | $ | 2,201 |
|
Accumulated benefit obligation, end of year | $ | 1,637 |
| | $ | 1,933 |
|
The funded status of the UK Plan and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Plan assets at fair value, end of year | $ | 2,363 | | | $ | 2,334 | |
Benefit obligation, end of year | 2,003 | | | 2,205 | |
Funded status | $ | 360 | | | $ | 129 | |
| | | |
Amounts recognized on the Consolidated Balance Sheets: | | | |
Other assets | $ | 360 | | | $ | 129 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Plan assets at fair value, end of year | $ | 1,989 |
| | $ | 2,368 |
|
Benefit obligation, end of year | 1,833 |
| | 2,201 |
|
Funded status | $ | 156 |
| | $ | 167 |
|
| | | |
Amounts recognized on the Consolidated Balance Sheets: | | | |
Other assets | $ | 156 |
| | $ | 167 |
|
Unrecognized Amounts
The portion of the funded status of the UK Plan not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Net loss | $ | 400 | | | $ | 612 | |
Prior service cost | 5 | | | 6 | |
Total | $ | 405 | | | $ | 618 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Net loss | $ | 472 |
| | $ | 510 |
|
Prior service cost | 8 |
| | — |
|
Total | $ | 480 |
| | $ | 510 |
|
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost, which are included in accumulated other comprehensive loss on the Consolidated Balance Sheets, for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Balance, beginning of year | $ | 618 | | | $ | 549 | |
Net loss arising during the year | (143) | | | 108 | |
| | | |
Settlement | (10) | | | (17) | |
Net amortization | (55) | | | (43) | |
Foreign currency exchange rate changes | (5) | | | 21 | |
Total | (213) | | | 69 | |
Balance, end of year | $ | 405 | | | $ | 618 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Balance, beginning of year | $ | 510 |
| | $ | 590 |
|
Net (gain) loss arising during the year | 59 |
| | (50 | ) |
Net prior service cost arising during the year | 8 |
| | — |
|
Settlement | (22 | ) | | (17 | ) |
Net amortization | (45 | ) | | (63 | ) |
Foreign currency exchange rate changes | (30 | ) | | 50 |
|
Total | (30 | ) | | (80 | ) |
Balance, end of year | $ | 480 |
| | $ | 510 |
|
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | 2018 | | 2017 | | 2016 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Benefit obligations as of December 31: | | | | | | Benefit obligations as of December 31: | |
Discount rate | 2.90 | % | | 2.60 | % | | 2.70 | % | Discount rate | 1.95 | % | | 1.40 | % | | 2.10 | % |
Rate of compensation increase | 3.55 | % | | 3.45 | % | | 3.00 | % | Rate of compensation increase | 3.45 | % | | 3.05 | % | | 3.30 | % |
Rate of future price inflation | 3.05 | % | | 2.95 | % | | 3.00 | % | Rate of future price inflation | 2.95 | % | | 2.55 | % | | 2.80 | % |
| | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | Net periodic benefit cost for the years ended December 31: | |
Discount rate | 2.60 | % | | 2.70 | % | | 3.70 | % | Discount rate | 1.40 | % | | 2.10 | % | | 2.90 | % |
Expected return on plan assets | 4.90 | % | | 5.00 | % | | 5.60 | % | Expected return on plan assets | 4.85 | % | | 5.00 | % | | 5.10 | % |
Rate of compensation increase | 3.45 | % | | 3.00 | % | | 2.90 | % | Rate of compensation increase | 3.05 | % | | 3.30 | % | | 3.55 | % |
Rate of future price inflation | 2.95 | % | | 3.00 | % | | 2.90 | % | Rate of future price inflation | 2.55 | % | | 2.80 | % | | 3.05 | % |
Contributions and Benefit Payments
Employer contributions to the UK Plan are expected to be £43£12 million during 2019.2022. The expected benefit payments to participants in the UK Plan for 20192022 through 20232026 and for the five years thereafter, excluding lump sum settlement elections and using the foreign currency exchange rate as of December 31, 2018,2021, are summarized below (in millions):
|
| | | |
2019 | $ | 70 |
|
2020 | 71 |
|
2021 | 73 |
|
2022 | 75 |
|
2023 | 77 |
|
2024-2028 | 416 |
|
| | | | | |
2022 | $ | 73 | |
2023 | 75 | |
2024 | 77 | |
2025 | 79 | |
2026 | 81 | |
2027-2031 | 436 | |
Plan Assets
Investment Policy and Asset Allocations
The investment policy for the UK Plan is to balance risk and return through a diversified portfolio of debt securities, equity securities, real estate and other asset classes. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The UK Plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with Northern Powergrid. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments. The return on assets assumption is based on a weighted-average of the expected historical performance for the types of assets in which the UK Plan invests.
The target allocations (percentage of plan assets) for the UK Plan assets are as follows as of December 31, 2018:
| | | | | |
| |
| % |
Debt securities(1) | 50-5560-70 |
Equity securities(1) | 35-4010-20 |
Real estate funds and other | 5-1515-25 |
| |
(1) | For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying investments in debt and equity securities. |
(1)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of the UK Plan assets, by major category (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | 5 | | | $ | 27 | | | $ | — | | | $ | 32 | |
Debt securities: | | | | | | | |
United Kingdom government obligations | 1,308 | | | — | | | — | | | 1,308 | |
| | | | | | | |
| | | | | | | |
Equity securities: | | | | | | | |
Investment funds(2) | — | | | 646 | | | — | | | 646 | |
Real estate funds | — | | | — | | | 269 | | | 269 | |
Total | $ | 1,313 | | | $ | 673 | | | $ | 269 | | | 2,255 | |
Investment funds(2) measured at net asset value | | | | | | | 108 | |
Total assets measured at fair value | | | | | | | $ | 2,363 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | 5 | | | $ | 49 | | | $ | — | | | $ | 54 | |
Debt securities: | | | | | | | |
| | | | | | | |
United Kingdom government obligations | 1,102 | | | — | | | — | | | 1,102 | |
| | | | | | | |
| | | | | | | |
Equity securities: | | | | | | | |
Investment funds(2) | — | | | 833 | | | — | | | 833 | |
Real estate funds | — | | | — | | | 237 | | | 237 | |
Total | $ | 1,107 | | | $ | 882 | | | $ | 237 | | | 2,226 | |
Investment funds(2) measured at net asset value | | | | | | | 108 | |
Total assets measured at fair value | | | | | | | $ | 2,334 | |
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2018: | | | | | | | |
Cash equivalents | $ | 3 |
| | $ | 59 |
| | $ | — |
| | $ | 62 |
|
Debt securities: | | | | | | | |
United Kingdom government obligations | 891 |
| | — |
| | — |
| | 891 |
|
Equity securities: | | | | | | | |
Investment funds(2) | — |
| | 697 |
| | — |
| | 697 |
|
Real estate funds | — |
| | — |
| | 239 |
| | 239 |
|
Total | $ | 894 |
| | $ | 756 |
| | $ | 239 |
| | 1,889 |
|
Investment funds(2) measured at net asset value | | | | | | | 100 |
|
Total assets measured at fair value | | | | | | | $ | 1,989 |
|
| | | | | | | |
As of December 31, 2017: | | | | | | | |
Cash equivalents | $ | 4 |
| | $ | 30 |
| | $ | — |
| | $ | 34 |
|
Debt securities: | | | | | | | |
United Kingdom government obligations | 870 |
| | — |
| | — |
| | 870 |
|
Equity securities: | | | | | | | |
Investment funds(2) | — |
| | 1,027 |
| | — |
| | 1,027 |
|
Real estate funds | — |
| | — |
| | 230 |
| | 230 |
|
Total | $ | 874 |
| | $ | 1,057 |
| | $ | 230 |
| | 2,161 |
|
Investment funds(2) measured at net asset value | | | | | | | 207 |
|
Total assets measured at fair value | | | | | | | $ | 2,368 |
|
| |
(1) | Refer to Note 14 for additional discussion regarding the three levels of the fair value hierarchy. |
| |
(2) | Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 36% and 64%, respectively, for 2018 and 21% and 79%, respectively, for 2017.
|
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 23% and 77%, respectively, for 2021 and 40% and 60%, respectively, for 2020.
The fair value of the UK Plan's assets are determined similar to the plan assets of the domestic plans as previously discussed.
The following table reconciles the beginning and ending balances of the UK Plan assets measured at fair valueusing significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Real Estate Funds |
| 2021 | | 2020 | | 2019 |
| | | | | |
Beginning balance | $ | 237 | | | $ | 243 | | | $ | 239 | |
Actual return on plan assets still held at period end | 35 | | | (13) | | | (5) | |
| | | | | |
Foreign currency exchange rate changes | (3) | | | 7 | | | 9 | |
Ending balance | $ | 269 | | | $ | 237 | | | $ | 243 | |
|
| | | | | | | | | | | |
| Real Estate Funds |
| 2018 | | 2017 | | 2016 |
| | | | |
|
Beginning balance | $ | 230 |
| | $ | 105 |
| | $ | 204 |
|
Actual return on plan assets still held at period end | 23 |
| | 6 |
| | 10 |
|
Purchases (sales) | — |
| | 104 |
| | (80 | ) |
Foreign currency exchange rate changes | (14 | ) | | 15 |
| | (29 | ) |
Ending balance | $ | 239 |
| | $ | 230 |
| | $ | 105 |
|
Defined Contribution Plans
The Company sponsors various defined contribution plans covering substantially all employees. The Company's contributions vary depending on the plan, but matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. The Company's contributions to these plans were $112$137 million,, $103 $127 million and $102$115 million for the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
177
| |
(13) | Asset Retirement Obligations
|
(14)Asset Retirement Obligations
The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $2.4 billion and $2.3$2.4 billion as of December 31, 20182021 and 2017, respectively.2020.
The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Fossil fuel facilities | $ | 466 | | | $ | 529 | |
Quad Cities Station | 427 | | | 376 | |
Wind generating facilities | 299 | | | 273 | |
Solar generating facilities | 25 | | | 24 | |
Offshore pipeline facilities | 14 | | | 16 | |
Other | 109 | | | 123 | |
Total asset retirement obligations | $ | 1,340 | | | $ | 1,341 | |
| | | |
Quad Cities Station nuclear decommissioning trust funds | $ | 768 | | | $ | 676 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Fossil fuel facilities | $ | 371 |
| | $ | 380 |
|
Quad Cities Station | 345 |
| | 342 |
|
Wind generating facilities | 174 |
| | 138 |
|
Offshore pipeline facilities | 33 |
| | 32 |
|
Solar generating facilities | 20 |
| | 19 |
|
Other | 42 |
| | 43 |
|
Total asset retirement obligations | $ | 985 |
| | $ | 954 |
|
| | | |
Quad Cities Station nuclear decommissioning trust funds | $ | 504 |
| | $ | 515 |
|
The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 1,341 | | | $ | 1,272 | |
Change in estimated costs | 81 | | | 46 | |
Acquisitions | — | | | 122 | |
Additions | 15 | | | 51 | |
Retirements | (144) | | | (201) | |
Accretion | 47 | | | 51 | |
Ending balance | $ | 1,340 | | | $ | 1,341 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 130 | | | $ | 184 | |
Other long-term liabilities | 1,210 | | | 1,157 | |
Total ARO liability | $ | 1,340 | | | $ | 1,341 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 954 |
| | $ | 954 |
|
Change in estimated costs | 10 |
| | (18 | ) |
Additions | 28 |
| | 21 |
|
Retirements | (45 | ) | | (45 | ) |
Accretion | 38 |
| | 42 |
|
Ending balance | $ | 985 |
| | $ | 954 |
|
| | | |
Reflected as: | | | |
Other current liabilities | $ | 43 |
| | $ | 60 |
|
Other long-term liabilities | 942 |
| | 894 |
|
Total ARO liability | $ | 985 |
| | $ | 954 |
|
The Nuclear Regulatory Commission regulates the decommissioning of nuclear power plants,generating facilities, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the Nuclear Regulatory Commission providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning.
Certain of the Company's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites, and as such, each subsidiary is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.
The changes in estimated costs relate primarily to the Quad Cities Station due to a change in the inflation rate and, for 2017, a new decommissioning study conducted by the operator of Quad Cities Station that changed the estimated amount and timing of cash flows.
In January 2018, MidAmerican Energy completed groundwater testing at its coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and will remove all CCR material located below the water table in such facilities, the latter of which is a more extensive closure activity than previously assumed. The incremental cost and timing of such actions is not currently reasonably determinable, but an evaluation of such estimates is expected to be completed in the first quarter of 2019, with any necessary adjustments to the related asset retirement obligations recognized at that time.
(14)(15)Fair Value Measurements
The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.
The following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2021: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | 5 | | | $ | 271 | | | $ | 73 | | | $ | (47) | | | $ | 302 | |
Foreign currency exchange rate derivatives | — | | | 3 | | | — | | | — | | | 3 | |
Interest rate derivatives | 1 | | | 3 | | | 20 | | | — | | | 24 | |
Mortgage loans held for sale | — | | | 1,263 | | | — | | | — | | | 1,263 | |
Money market mutual funds | 554 | | | — | | | — | | | — | | | 554 | |
Debt securities: | | | | | | | | | |
United States government obligations | 232 | | | — | | | — | | | — | | | 232 | |
International government obligations | — | | | 2 | | | — | | | — | | | 2 | |
Corporate obligations | — | | | 90 | | | — | | | — | | | 90 | |
Municipal obligations | — | | | 3 | | | — | | | — | | | 3 | |
Agency, asset and mortgage-backed obligations | — | | | 2 | | | — | | | — | | | 2 | |
| | | | | | | | | |
Equity securities: | | | | | | | | | |
United States companies | 428 | | | — | | | — | | | — | | | 428 | |
International companies | 7,703 | | | — | | | — | | | — | | | 7,703 | |
Investment funds | 237 | | | — | | | — | | | — | | | 237 | |
| $ | 9,160 | | | $ | 1,637 | | | $ | 93 | | | $ | (47) | | | $ | 10,843 | |
Liabilities: | | | | | | | | | |
Commodity derivatives | $ | (2) | | | $ | (113) | | | $ | (224) | | | $ | 73 | | | $ | (266) | |
Foreign currency exchange rate derivatives | — | | | (3) | | | — | | | — | | | (3) | |
Interest rate derivatives | — | | | (7) | | | (1) | | | — | | | (8) | |
| $ | (2) | | | $ | (123) | | | $ | (225) | | | $ | 73 | | | $ | (277) | |
| | | Input Levels for Fair Value Measurements | | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total | |
As of December 31, 2018: | | | | | | | | | | |
As of December 31, 2020: | | As of December 31, 2020: | |
Assets: | | | | | | | | | | Assets: | |
Commodity derivatives | $ | 1 |
| | $ | 91 |
| | $ | 108 |
| | $ | (52 | ) | | $ | 148 |
| Commodity derivatives | $ | 1 | | | $ | 73 | | | $ | 135 | | | $ | (21) | | | $ | 188 | |
Foreign currency exchange rate derivatives | | Foreign currency exchange rate derivatives | — | | | 20 | | | — | | | — | | | 20 | |
Interest rate derivatives | 1 |
| | 13 |
| | 10 |
| | — |
| | 24 |
| Interest rate derivatives | — | | | — | | | 62 | | | — | | | 62 | |
Mortgage loans held for sale | — |
| | 468 |
| | — |
| | — |
| | 468 |
| Mortgage loans held for sale | — | | | 2,001 | | | — | | | — | | | 2,001 | |
Money market mutual funds(2) | 409 |
| | — |
| | — |
| | — |
| | 409 |
| 873 | | | — | | | — | | | — | | | 873 | |
Debt securities: | | | | | | | | | | Debt securities: | |
United States government obligations | 187 |
| | — |
| | — |
| | — |
| | 187 |
| United States government obligations | 200 | | | — | | | — | | | — | | | 200 | |
International government obligations | — |
| | 4 |
| | — |
| | — |
| | 4 |
| International government obligations | — | | | 5 | | | — | | | — | | | 5 | |
Corporate obligations | — |
| | 46 |
| | — |
| | — |
| | 46 |
| Corporate obligations | — | | | 73 | | | — | | | — | | | 73 | |
Municipal obligations | — |
| | 2 |
| | — |
| | — |
| | 2 |
| Municipal obligations | — | | | 2 | | | — | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | — |
| | 1 |
| | — |
| | — |
| | 1 |
| Agency, asset and mortgage-backed obligations | — | | | 6 | | | — | | | — | | | 6 | |
| Equity securities: | | | | | | | | | | Equity securities: | |
United States companies | 256 |
| | — |
| | — |
| | — |
| | 256 |
| United States companies | 381 | | | — | | | — | | | — | | | 381 | |
International companies | 1,441 |
| | — |
| | — |
| | — |
| | 1,441 |
| International companies | 5,906 | | | — | | | — | | | — | | | 5,906 | |
Investment funds | 128 |
| | — |
| | — |
| | — |
| | 128 |
| Investment funds | 201 | | | — | | | — | | | — | | | 201 | |
| $ | 2,423 |
| | $ | 625 |
| | $ | 118 |
| | $ | (52 | ) | | $ | 3,114 |
| | $ | 7,562 | | | $ | 2,180 | | | $ | 197 | | | $ | (21) | | | $ | 9,918 | |
Liabilities: | | | | | | | | | | Liabilities: | | | | | | | | | |
Commodity derivatives | $ | (1 | ) | | $ | (180 | ) | | $ | (9 | ) | | $ | 111 |
| | $ | (79 | ) | Commodity derivatives | $ | (1) | | | $ | (90) | | | $ | (19) | | | $ | 56 | | | $ | (54) | |
Foreign currency exchange rate derivatives | | Foreign currency exchange rate derivatives | — | | | (2) | | | — | | | — | | | (2) | |
Interest rate derivatives | — |
| | (32 | ) | | — |
| | — |
| | (32 | ) | Interest rate derivatives | (5) | | | (60) | | | — | | | — | | | (65) | |
| $ | (1 | ) | | $ | (212 | ) | | $ | (9 | ) | | $ | 111 |
| | $ | (111 | ) | | $ | (6) | | | $ | (152) | | | $ | (19) | | | $ | 56 | | | $ | (121) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $26 million and $35 million as of December 31, 2021 and 2020, respectively. |
| | | | | | | | | | | | | | | | | | | |
As of December 31, 2017: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | 1 |
| | $ | 42 |
| | $ | 104 |
| | $ | (29 | ) | | $ | 118 |
|
Interest rate derivatives | — |
| | 15 |
| | 9 |
| | — |
| | 24 |
|
Mortgage loans held for sale | — |
| | 465 |
| | — |
| | — |
| | 465 |
|
Money market mutual funds(2) | 685 |
| | — |
| | — |
| | — |
| | 685 |
|
Debt securities: | | | | | | | | | |
United States government obligations | 176 |
| | — |
| | — |
| | — |
| | 176 |
|
International government obligations | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Corporate obligations | — |
| | 36 |
| | — |
| | — |
| | 36 |
|
Municipal obligations | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Equity securities: | | | | | | | | | |
United States companies | 288 |
| | — |
| | — |
| | — |
| | 288 |
|
International companies | 1,968 |
| | — |
| | — |
| | — |
| | 1,968 |
|
Investment funds | 178 |
| | — |
| | — |
| | — |
| | 178 |
|
| $ | 3,296 |
| | $ | 565 |
| | $ | 113 |
| | $ | (29 | ) | | $ | 3,945 |
|
Liabilities: | | | | | | | | | |
Commodity derivatives | $ | (3 | ) | | $ | (167 | ) | | $ | (10 | ) | | $ | 105 |
| | $ | (75 | ) |
Interest rate derivatives | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) |
| $ | (3 | ) | | $ | (175 | ) | | $ | (10 | ) | | $ | 105 |
| | $ | (83 | ) |
| |
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $59 million and $76 million as of December 31, 2018 and 2017, respectively.
|
| |
(2) | Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
The following table reconciles the beginning and ending balances of the Company's financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Derivatives | | Interest Rate Derivatives | | |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | | | | | |
| | | | | | | | | | | | | | | | | |
Beginning balance | $ | 116 | | | $ | 97 | | | $ | 99 | | | $ | 62 | | | $ | 14 | | | $ | 10 | | | | | | | |
Changes included in earnings(1) | (43) | | | (10) | | | 10 | | | (43) | | | 48 | | | 4 | | | | | | | |
Changes in fair value recognized in OCI | (13) | | | — | | | (1) | | | — | | | — | | | — | | | | | | | |
Changes in fair value recognized in net regulatory assets | (118) | | | (17) | | | (26) | | | — | | | — | | | — | | | | | | | |
| | | | | | | | | | | | | | | | | |
Purchases | (76) | | | 5 | | | 6 | | | — | | | — | | | — | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Settlements | (34) | | | 41 | | | 9 | | | — | | | — | | | — | | | | | | | |
Transfers to Level 2 | 17 | | | — | | | — | | | — | | | — | | | — | | | | | | | |
| | | | | | | | | | | | | | | | | |
Ending balance | $ | (151) | | | $ | 116 | | | $ | 97 | | | $ | 19 | | | $ | 62 | | | $ | 14 | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Derivatives | | Interest Rate Derivatives | | Auction Rate Securities |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | | | | | | | |
Beginning balance | $ | 94 |
| | $ | 60 |
| | $ | 47 |
| | $ | 9 |
| | $ | 6 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 44 |
|
Changes included in earnings | 1 |
| | 23 |
| | 8 |
| | 181 |
| | 147 |
| | 121 |
| | — |
| | — |
| | 5 |
|
Changes in fair value recognized in OCI | 2 |
| | (3 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
Changes in fair value recognized in net regulatory assets | 3 |
| | (1 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Purchases | 3 |
| | 1 |
| | 1 |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| | — |
|
Redemptions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) |
Settlements | (4 | ) | | 14 |
| | 17 |
| | (180 | ) | | (148 | ) | | (119 | ) | | — |
| | — |
| | — |
|
Ending balance | $ | 99 |
| | $ | 94 |
| | $ | 60 |
| | $ | 10 |
| | $ | 9 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
|
(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.
The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 49,762 | | | $ | 57,189 | | | $ | 49,866 | | | $ | 60,633 | |
|
| | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 36,774 |
| | $ | 39,398 |
| | $ | 35,193 |
| | $ | 40,522 |
|
(15)(16)Commitments and Contingencies
Commitments
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 20182021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 2027 and | | |
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | | $ | 2,475 | | | $ | 1,635 | | | $ | 1,422 | | | $ | 1,164 | | | $ | 1,054 | | | $ | 11,964 | | | $ | 19,714 | |
Construction commitments | | 1,329 | | | 831 | | | 776 | | | 87 | | | 4 | | | — | | | 3,027 | |
Easements | | 82 | | | 84 | | | 80 | | | 82 | | | 83 | | | 2,870 | | | 3,281 | |
Maintenance, service and other contracts | | 474 | | | 364 | | | 300 | | | 249 | | | 240 | | | 1,543 | | | 3,170 | |
| | $ | 4,360 | | | $ | 2,914 | | | $ | 2,578 | | | $ | 1,582 | | | $ | 1,381 | | | $ | 16,377 | | | $ | 29,192 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 2024 and | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | | $ | 2,215 |
| | $ | 1,659 |
| | $ | 1,380 |
| | $ | 1,174 |
| | $ | 1,047 |
| | $ | 11,155 |
| | $ | 18,630 |
|
Construction commitments | | 2,330 |
| | 587 |
| | 52 |
| | — |
| | — |
| | — |
| | 2,969 |
|
Operating leases and easements | | 197 |
| | 177 |
| | 160 |
| | 139 |
| | 111 |
| | 1,738 |
| | 2,522 |
|
Maintenance, service and other contracts | | 306 |
| | 344 |
| | 303 |
| | 277 |
| | 241 |
| | 1,358 |
| | 2,829 |
|
| | $ | 5,048 |
| | $ | 2,767 |
| | $ | 1,895 |
| | $ | 1,590 |
| | $ | 1,399 |
| | $ | 14,251 |
| | $ | 26,950 |
|
Fuel, Capacity and Transmission Contract Commitments
The Utilities have fuel supply and related transportation and lime contracts for their coal- and natural gas-fueled generating facilities. The Utilities expect to supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. The Utilities acquire a portion of their electricity through long-term purchases and exchange agreements. The Utilities have several power purchase agreements with renewable generating facilities that are not included in the table above as the payments are based on the amount of energy generated and there are no minimum payments. The Utilities also have contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to their customers.
MidAmerican Energy has long-term rail transportation contracts with BNSF Railway Company ("BNSF"), an affiliate company, and Union Pacific Railroad Company for the transportation of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities. For the years ended December 31, 2018, 20172021, 2020 and 2016, $1112019, $76 million, $109$90 million and $137$123 million, respectively, were incurred for coal transportation services, the majority of which was related to the BNSF agreement.
Construction Commitments
The Company's firm construction commitments reflected in the table above include the following major construction projects:
MidAmerican Energy's construction of wind-powered generating facilities and the last of the four Multi-Value Projects approved by the Midcontinent Independent System Operator, Inc. for high voltage transmission lines in Iowa and Illinois in 2018.
ALP's investments in directly assigned transmission projects from the AESO.
•PacifiCorp's costs associated with certain generating plant, transmission, and distribution projects.
•MidAmerican Energy's firm construction commitments primarily consisting of contracts for the repowering and construction of wind-powered generating facilities and solar-powered generating facilities and the settlement of AROs.
•Nevada Utilities' firm construction commitments consisting of costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada and certain other generating plant projects and costs associated with two additional solar photovoltaic facility projects. The first project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. Both facilities will be jointly owned and operated by Nevada Power and Sierra Pacific.
Operating Leases and •AltaLink's investments in directly assigned transmission projects from the AESO.
Easements
The Company has non-cancelable operating leases primarily for office equipment, office space, certain operating facilities, land and rail cars. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company also has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located. Rent expense on non-cancelable operating leases and easements totaled $191 million for 2018 and $156 million for both 2017 and 2016.
Maintenance, Service and Other Contracts
The Company has entered into service agreements related to its nonregulated solarwind-powered and wind-poweredsolar-powered projects with third parties to operate and maintain the projects under fixed-fee operating and maintenance agreements. Additionally, thethe Company has various non-cancelable maintenance, service and other contracts primarily related to turbine and equipment maintenance and various other service agreements.
BHE Renewables' Counterparty Risk
On January 29, 2019, PG&E filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California. The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement that is in effect until October 2039. As of December 31, 2018, the Company's consolidated balance sheet includes $1.1 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement that is in effect until June 2039. As of December 31, 2018, the Company's equity investment in Agua Caliente totals $44 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. PG&E paid in full the December invoices for both Topaz and Agua Caliente, which were payable January 25, 2019. In addition, the Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company believes it is more likely than not that no impairment exists as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation.
Legal Matters
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. Additionally, multiple insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectric systemPacifiCorp is currently operating under annual licenses witha party to the FERC. In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed the2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"). Among, which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other things, the KHSA provided that the United States Department of the Interior would conduct scientific and engineering studiesstakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the Klamath hydroelectric system's mainstem dams wassettlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in the public interest and would advance restorationCalifornia bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Klamath Basin's salmonid fisheries. If it is determinedFederal Energy Regulatory Commission ("FERC") license to a third-party dam removal should proceed, dam removal would begin no earlier than 2020.
Congress failed to pass legislation needed to implement the original KHSA. In April 2016, the principal parties to the KHSA (PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce) executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, in September 2016, PacifiCorp andentity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a private, independent nonprofit 501(c)(3) organization formed by certain signatories of the amended KSHA, jointly filed anjoint application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilitiesdams from PacifiCorp to the KRRC. Also in September 2016, the KRRC filed an application with theThe FERC to surrender the license and decommission the same four facilities. The KRRC's license surrender application included a request for the FERC to refrain from acting on the surrender application until after theapproved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, is effective. In March 2018, the FERC issued an order splittingKaruk Tribe, the existingYurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application to remove PacifiCorp from the license for the Klamath Hydroelectric Project into two licenses:and add the Klamath Project (P‑2082) contains East Side, West Side, KenoStates and Fall Creek developments;KRRC as co-licensees for the new Lower Klamath Project (P‑14803) contains J.C. Boyle, Copco No. 1, Copco No. 2purposes of surrender. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and Iron Gate developments.the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In the same order,June 2021, the FERC deferred consideration of theapproved transfer of the license for the Lowerfour mainstem Klamath facilitiesdams from PacifiCorp to the KRRC until some point inand the future.States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp is currentlynotified the licensee for both the Klamath Project and Lower Klamath Project facilities and will retain ownershipPublic Service Commission of Utah of the Klamath Project facilities afterproperty transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the approval and transferissuance of the Lower Klamath Project facilities. In April 2018, PacifiCorp filed a motion to stay the effective date of the license amendment until transfer is approved. In June 2018,surrender from the FERC granted PacifiCorp's motion to stay the effective date of the Lower Klamath Project license and all related compliance obligations, pending a FERC order on the license transfer. Meanwhile, the FERC continues to assess the KRRC's capacity to become a project licensee for purposes of dam removal. The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, on January 25, 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project, relicensing. PacifiCorp is evaluating the impact of this decision.which remains pending.
Under the amended KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution toward facilities removal costs are being drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and the state of California, sufficient funds would need to be provided by the KRRC or an entity other than PacifiCorp for removal to proceed.
If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.
As of December 31, 2018,2021, PacifiCorp's assets included $44$14 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through either December 31, 2019, or December 31, 2022, depending upon the state jurisdiction.2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities. PacifiCorp estimates it is obligatedfacilities, which are estimated to make capital expenditures ofbe approximately $155$193 million over the next 10 years related toyears. Included in these licenses.estimates are commitments associated with the KHSA.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
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(16) | BHE Shareholders' Equity
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(17) Revenue from Contracts with Customers
Energy Products and Services
The following table summarizes the Company's energy products and services Customer Revenue by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 22, for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,847 | | | $ | 2,128 | | | $ | 2,828 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 9,801 | |
Retail Gas | | — | | | 859 | | | 115 | | | — | | | — | | | — | | | — | | | — | | | 974 | |
Wholesale | | 157 | | | 454 | | | 62 | | | — | | | 57 | | | — | | | — | | | (3) | | | 727 | |
Transmission and distribution | | 143 | | | 58 | | | 74 | | | 1,023 | | | — | | | 702 | | | — | | | — | | | 2,000 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 2,404 | | | — | | | — | | | (131) | | | 2,273 | |
Other | | 108 | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | 1 | | | 109 | |
Total Regulated | | 5,255 | | | 3,499 | | | 3,080 | | | 1,023 | | | 2,460 | | | 702 | | | — | | | (135) | | | 15,884 | |
Nonregulated | | — | | | 15 | | | 3 | | | 43 | | | 956 | | | 35 | | | 796 | | | 576 | | | 2,424 | |
Total Customer Revenue | | 5,255 | | | 3,514 | | | 3,083 | | | 1,066 | | | 3,416 | | | 737 | | | 796 | | | 441 | | | 18,308 | |
Other revenue | | 41 | | | 33 | | | 24 | | | 122 | | | 128 | | | (6) | | | 185 | | | 100 | | | 627 | |
Total | | $ | 5,296 | | | $ | 3,547 | | | $ | 3,107 | | | $ | 1,188 | | | $ | 3,544 | | | $ | 731 | | | $ | 981 | | | $ | 541 | | | $ | 18,935 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,932 | | | $ | 1,924 | | | $ | 2,566 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 9,421 | |
Retail Gas | | — | | | 505 | | | 114 | | | — | | | — | | | — | | | — | | | — | | | 619 | |
Wholesale | | 107 | | | 199 | | | 45 | | | — | | | 17 | | | — | | | — | | | (2) | | | 366 | |
Transmission and distribution | | 96 | | | 60 | | | 95 | | | 887 | | | — | | | 641 | | | — | | | — | | | 1,779 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 1,397 | | | — | | | — | | | (139) | | | 1,258 | |
Other | | 108 | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | 110 | |
Total Regulated | | 5,243 | | | 2,688 | | | 2,822 | | | 887 | | | 1,414 | | | 641 | | | — | | | (142) | | | 13,553 | |
Nonregulated | | — | | | 16 | | | 2 | | | 26 | | | 134 | | | 18 | | | 817 | | | 515 | | | 1,528 | |
Total Customer Revenue | | 5,243 | | | 2,704 | | | 2,824 | | | 913 | | | 1,548 | | | 659 | | | 817 | | | 373 | | | 15,081 | |
Other revenue | | 98 | | | 24 | | | 30 | | | 109 | | | 30 | | | — | | | 119 | | | 65 | | | 475 | |
Total | | $ | 5,341 | | | $ | 2,728 | | | $ | 2,854 | | | $ | 1,022 | | | $ | 1,578 | | | $ | 659 | | | $ | 936 | | | $ | 438 | | | $ | 15,556 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,789 | | | $ | 1,938 | | | $ | 2,740 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 9,465 | |
Retail Gas | | — | | | 570 | | | 116 | | | — | | | — | | | — | | | — | | | — | | | 686 | |
Wholesale | | 99 | | | 309 | | | 51 | | | — | | | — | | | — | | | — | | | (2) | | | 457 | |
Transmission and distribution | | 98 | | | 57 | | | 98 | | | 876 | | | — | | | 690 | | | — | | | — | | | 1,819 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 1,122 | | | — | | | — | | | (118) | | | 1,004 | |
Other | | — | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | 2 | |
Total Regulated | | 4,986 | | | 2,874 | | | 3,007 | | | 876 | | | 1,122 | | | 690 | | | — | | | (122) | | | 13,433 | |
Nonregulated | | — | | | 30 | | | — | | | 36 | | | — | | | 17 | | | 744 | | | 577 | | | 1,404 | |
Total Customer Revenue | | 4,986 | | | 2,904 | | | 3,007 | | | 912 | | | 1,122 | | | 707 | | | 744 | | | 455 | | | 14,837 | |
Other revenue | | 82 | | | 23 | | | 30 | | | 101 | | | 9 | | | — | | | 188 | | | 101 | | | 534 | |
Total | | $ | 5,068 | | | $ | 2,927 | | | $ | 3,037 | | | $ | 1,013 | | | $ | 1,131 | | | $ | 707 | | | $ | 932 | | | $ | 556 | | | $ | 15,371 | |
(1)The BHE and Other reportable segment represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| HomeServices |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Brokerage | $ | 5,498 | | | $ | 4,520 | | | $ | 4,028 | |
Franchise | 85 | | | 76 | | | 68 | |
Total Customer Revenue | 5,583 | | | 4,596 | | | 4,096 | |
Mortgage and other revenue | 632 | | | 800 | | | 377 | |
Total | $ | 6,215 | | | $ | 5,396 | | | $ | 4,473 | |
Remaining Performance Obligations
The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2021, by reportable segment (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
BHE Pipeline Group | $ | 2,607 | | | $ | 21,038 | | | $ | 23,645 | |
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(18)BHE Shareholders' Equity
Preferred Stock
As of December 31, 2021 and 2020, BHE had 1,649,988 and 3,750,000 shares outstanding of its Perpetual Preferred Stock (the "4% Perpetual Preferred Stock") issued to certain subsidiaries of Berkshire Hathaway Inc. The 4% Perpetual Preferred Stock has a liquidation preference of $1,000 per share and currently pays a 4.00% dividend per share on the liquidation preference. Dividends shall accrue and accumulate daily, be cumulative, compound semi-annually and, if declared, be payable in cash semi-annually in arrears on May 15 and November 15 of each year. If dividends are not declared and paid, any accumulating dividends shall continue to accumulate and compound. BHE may not make any dividends on shares of any other class or series of its capital stock (other than for dividends on shares of common stock payable in shares of common stock, unless the holders of the then outstanding 4% Perpetual Preferred Stock shall first receive, or simultaneously receive, a dividend in an amount at least equivalent to the amount accumulated and not previously paid. BHE may not declare or pay any dividends on shares of the 4% Perpetual Preferred Stock if such declaration or payment would constitute an event of default on BHE's senior indebtedness (as defined). BHE may, at its option, redeem the 4% Perpetual Preferred Stock in whole or in part at any time at a price per share equal to the liquidation preference.
Common Stock
On March 14, 2000, and as amended on December 7, 2005, BHE's shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares to BHE at the then-current fair value dependent on certain circumstances controlled by BHE.
For the years ended December 31, 2018 and 2017, BHE repurchased 177,381 shares of its common stock for $107 million and 35,000 shares of its common stock for $19 million, respectively.
For the year ended December 31, 2017, BHE issued $100 million of its 5.00% junior subordinated debentures due June 2057 in exchange for 181,819 shares of its common stock.
In February 2019, BHE repurchased 447,712 shares of its common stock for $293 million.
Restricted Net Assets
BHE has maximum debt-to-total capitalization percentage restrictions imposed by its senior unsecured credit facilities expiring in June 20212024 which, in certain circumstances, limit BHE's ability to make cash dividends or distributions. As a result of this restriction, BHE has restricted net assets of $16.5$18.3 billion as of December 31, 2018.2021.
Certain of BHE's subsidiaries have restrictions on their ability to dividend, loan or advance funds to BHE due to specific legal or regulatory restrictions, including, but not limited to, maximum debt-to-total capitalization percentages and commitments made to state commissions or federal agencies in connection with past acquisitions.commissions. As a result of these restrictions, BHE's subsidiaries had restricted net assets of $20.7$20.3 billion as of December 31, 2018.2021.
(17)
(19)Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
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| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Unrecognized | | Foreign | | | | Unrealized | | | | AOCI |
| | Amounts on | | Currency | | | | Gains (Losses) | | | | Attributable |
| | Retirement | | Translation | | | | on Cash Flow | | Noncontrolling | | To BHE |
| | Benefits | | Adjustment | | | | Hedges | | Interests | | Shareholders, Net |
| | | | | | | | | | | | |
Balance, December 31, 2018 | | $ | (358) | | | $ | (1,623) | | | | | $ | 36 | | | $ | — | | | $ | (1,945) | |
Other comprehensive (loss) income | | (59) | | | 327 | | | | | (29) | | | — | | | 239 | |
Balance, December 31, 2019 | | (417) | | | (1,296) | | | | | 7 | | | — | | | (1,706) | |
Other comprehensive (loss) income | | (65) | | | 234 | | | | | (15) | | | — | | | 154 | |
BHE GT&S acquisition | | (10) | | | — | | | | | — | | | 10 | | | — | |
Balance, December 31, 2020 | | (492) | | | (1,062) | | | | | (8) | | | 10 | | | (1,552) | |
Other comprehensive income (loss) | | 174 | | | (24) | | | | | 67 | | | (5) | | | 212 | |
Balance, December 31, 2021 | | $ | (318) | | | $ | (1,086) | | | | | $ | 59 | | | $ | 5 | | | $ | (1,340) | |
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| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | Unrecognized | | Foreign | | Unrealized | | Unrealized | | AOCI |
| | Amounts on | | Currency | | Gains on | | Gains on | | Attributable |
| | Retirement | | Translation | | Marketable | | Cash Flow | | To BHE |
| | Benefits | | Adjustment | | Securities | | Hedges | | Shareholders, Net |
| | | | | | | | | | |
Balance, December 31, 2015 | | $ | (438 | ) | | $ | (1,092 | ) | | $ | 615 |
| | $ | 7 |
| | $ | (908 | ) |
Other comprehensive (loss) income | | (9 | ) | | (583 | ) | | (30 | ) | | 19 |
| | (603 | ) |
Balance, December 31, 2016 | | (447 | ) | | (1,675 | ) | | 585 |
| | 26 |
| | (1,511 | ) |
Other comprehensive income | | 64 |
| | 546 |
| | 500 |
| | 3 |
| | 1,113 |
|
Balance, December 31, 2017 | | (383 | ) | | (1,129 | ) | | 1,085 |
| | 29 |
| | (398 | ) |
Adoption of ASU 2016-01 | | — |
| | — |
| | (1,085 | ) | | — |
| | (1,085 | ) |
Other comprehensive income (loss) | | 25 |
| | (494 | ) | | — |
| | 7 |
| | (462 | ) |
Balance, December 31, 2018 | | $ | (358 | ) | | $ | (1,623 | ) | | $ | — |
| | $ | 36 |
| | $ | (1,945 | ) |
Reclassifications from AOCI to net income for the years ended December 31, 2018, 20172021, 2020 and 20162019 were insignificant. Additionally, refer to the "Foreign Operations" discussion in Note 1213 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.
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(18) | Noncontrolling Interests
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(20)Variable Interest Entities and Noncontrolling Interests
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As part of the GT&S Transaction, BHE acquired an indirect 25% economic interest in Cove Point, consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. BHE is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Included in noncontrolling interests on the Consolidated Balance Sheets are (i) Dominion Energy's 50% interest in Cove Point and Brookfield Super-Core Infrastructure Partner's 25% interest in Cove Point and (ii) preferred securities of subsidiaries of $58$58 million as of December 31, 20182021 and 2017,2020, consisting of $56 million of 8.061% cumulative preferred securities of Northern Electric plc.,plc, a subsidiary of Northern Powergrid, which are redeemable in the event of the revocation of Northern Electric plc.'splc's electricity distribution license by the Secretary of State, and $2 million of nonredeemable preferred stock of PacifiCorp.
(19) Revenue from Contracts with Customers
The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The following table summarizes the Company's energy products and services revenue by regulated energy and nonregulated energy, with further disaggregation of regulated energy by customer class and line of business, including a reconciliation to the Company's reportable segment information included in Note 21 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2018 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,732 |
| | $ | 1,915 |
| | $ | 2,773 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | 9,419 |
|
Retail Gas | | — |
| | 636 |
| | 101 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 737 |
|
Wholesale | | 55 |
| | 411 |
| | 39 |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 501 |
|
Transmission and distribution | | 103 |
| | 56 |
| | 96 |
| | 892 |
| | — |
| | 700 |
| | — |
| | (1 | ) | | 1,846 |
|
Interstate pipeline | | — |
| | — |
| | — |
| | — |
| | 1,232 |
| | — |
| | — |
| | (125 | ) | | 1,107 |
|
Other | | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
Total Regulated | | 4,890 |
| | 3,018 |
| | 3,011 |
| | 892 |
| | 1,232 |
| | 700 |
| | — |
| | (131 | ) | | 13,612 |
|
Nonregulated | | — |
| | 14 |
| | — |
| | 39 |
| | — |
| | 10 |
| | 673 |
| | 624 |
| | 1,360 |
|
Total Customer Revenue | | 4,890 |
| | 3,032 |
| | 3,011 |
| | 931 |
| | 1,232 |
| | 710 |
| | 673 |
| | 493 |
| | 14,972 |
|
Other revenue(2) | | 136 |
| | 21 |
| | 28 |
| | 89 |
| | (29 | ) | | — |
| | 235 |
| | 121 |
| | 601 |
|
Total | | $ | 5,026 |
| | $ | 3,053 |
| | $ | 3,039 |
| | $ | 1,020 |
| | $ | 1,203 |
| | $ | 710 |
| | $ | 908 |
| | $ | 614 |
| | $ | 15,573 |
|
| |
(1) | The BHE and Other reportable segment represents amounts related principally to other entities, corporate functions and intersegment eliminations. |
| |
(2) | Includes net payments to counterparties for the financial settlement of certain derivative contracts at BHE Pipeline Group. |
Real Estate Services
The following table summarizes the Company's real estate services revenue by line of business (in millions):
|
| | | |
| HomeServices |
| Year Ended |
| Ended December 31, |
| 2018 |
Customer Revenue: | |
Brokerage | $ | 3,882 |
|
Franchise | 67 |
|
Total Customer Revenue | 3,949 |
|
Other revenue | 265 |
|
Total | $ | 4,214 |
|
Contract Assets and Liabilities
As of December 31, 2018 and December 31, 2017, there were no material contract assets or contract liabilities recorded on the Consolidated Balance Sheets. For the year ended December 31, 2018, there was no material revenue recognized that was included in the contract liability balance at the beginning of the period or from performance obligations satisfied in previous periods.
Remaining Performance Obligations
The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2018, by reportable segment (in millions):
|
| | | | | | | | | | | |
| Performance obligations expected to be satisfied: | | |
| Less than 12 months | | More than 12 months | | Total |
BHE Pipeline Group | $ | 842 |
| | $ | 5,678 |
| | $ | 6,520 |
|
(20)(21)Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2018 and December 31, 2017, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2018 and December 31, 2017, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 1,096 | | | $ | 1,290 | |
Restricted cash and cash equivalents | 127 | | | 140 | |
Investments and restricted cash and cash equivalents and investments | 21 | | | 15 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 1,244 | | | $ | 1,445 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
Cash and cash equivalents | $ | 627 |
| | $ | 935 |
|
Restricted cash and cash equivalents | 227 |
| | 327 |
|
Investments and restricted cash and cash equivalents and investments | 29 |
| | 21 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 883 |
| | $ | 1,283 |
|
The summary of supplemental cash flow disclosures as of and for the years endingended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 2,041 | | | $ | 1,855 | | | $ | 1,723 | |
Income taxes received, net(1) | $ | 1,309 | | | $ | 1,361 | | | $ | 850 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 834 | | | $ | 801 | | | $ | 888 | |
| | | | | |
(1)Includes $1,441 million, $1,504 million and $942 million of income taxes received from Berkshire Hathaway in 2021, 2020 and 2019, respectively.
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 1,713 |
| | $ | 1,715 |
| | $ | 1,673 |
|
Income taxes received, net(1) | $ | 780 |
| | $ | 540 |
| | $ | 1,016 |
|
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 823 |
| | $ | 653 |
| | $ | 547 |
|
Common stock exchanged for junior subordinated debentures | $ | — |
| | $ | 100 |
| | $ | — |
|
| |
(1) | Includes $884 million, $636 million and $1.1 billion of income taxes received from Berkshire Hathaway in 2018, 2017 and 2016, respectively. |
(21)(22)Segment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines.Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
PacifiCorp | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
MidAmerican Funding | 3,547 | | | 2,728 | | | 2,927 | |
NV Energy | 3,107 | | | 2,854 | | | 3,037 | |
Northern Powergrid | 1,188 | | | 1,022 | | | 1,013 | |
BHE Pipeline Group | 3,544 | | | 1,578 | | | 1,131 | |
BHE Transmission | 731 | | | 659 | | | 707 | |
BHE Renewables | 981 | | | 936 | | | 932 | |
HomeServices | 6,215 | | | 5,396 | | | 4,473 | |
BHE and Other(1) | 541 | | | 438 | | | 556 | |
Total operating revenue | $ | 25,150 | | | $ | 20,952 | | | $ | 19,844 | |
| | | | | |
Depreciation and amortization: | | | | | |
PacifiCorp | $ | 1,088 | | | $ | 1,209 | | | $ | 954 | |
MidAmerican Funding | 914 | | | 716 | | | 638 | |
NV Energy | 549 | | | 502 | | | 482 | |
Northern Powergrid | 305 | | | 266 | | | 254 | |
BHE Pipeline Group | 492 | | | 231 | | | 115 | |
BHE Transmission | 238 | | | 201 | | | 240 | |
BHE Renewables | 241 | | | 284 | | | 282 | |
HomeServices | 52 | | | 45 | | | 47 | |
BHE and Other(1) | 2 | | | 1 | | | (1) | |
Total depreciation and amortization | $ | 3,881 | | | $ | 3,455 | | | $ | 3,011 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | Years Ended December 31, |
| Years Ended December 31, | |
| 2018 | | 2017 | | 2016 | |
Operating revenue: | | | | | | |
PacifiCorp | $ | 5,026 |
| | $ | 5,237 |
| | $ | 5,201 |
| |
MidAmerican Funding | 3,053 |
| | 2,846 |
| | 2,631 |
| |
NV Energy | 3,039 |
| | 3,015 |
| | 2,895 |
| |
Northern Powergrid | 1,020 |
| | 949 |
| | 995 |
| |
BHE Pipeline Group | 1,203 |
| | 993 |
| | 978 |
| |
BHE Transmission | 710 |
| | 699 |
| | 502 |
| |
BHE Renewables | 908 |
| | 838 |
| | 743 |
| |
HomeServices | 4,214 |
| | 3,443 |
| | 2,801 |
| |
BHE and Other(1) | 614 |
| | 594 |
| | 676 |
| |
Total operating revenue | $ | 19,787 |
| | $ | 18,614 |
| | $ | 17,422 |
| |
| | | | | | |
Depreciation and amortization: | | | | | | |
PacifiCorp | $ | 979 |
| | $ | 796 |
| | $ | 783 |
| |
MidAmerican Funding | 609 |
| | 500 |
| | 479 |
| |
NV Energy | 456 |
| | 422 |
| | 421 |
| |
Northern Powergrid | 250 |
| | 214 |
| | 200 |
| |
BHE Pipeline Group | 126 |
| | 159 |
| | 206 |
| |
BHE Transmission | 247 |
| | 239 |
| | 241 |
| |
BHE Renewables | 268 |
| | 251 |
| | 230 |
| |
HomeServices | 51 |
| | 66 |
| | 31 |
| |
BHE and Other(1) | (2 | ) | | (1 | ) | | — |
| |
Total depreciation and amortization | $ | 2,984 |
| | $ | 2,646 |
| | $ | 2,591 |
| |
| | | | | | | 2021 | | 2020 | | 2019 |
Operating income: | | | | | | Operating income: | | | | | |
PacifiCorp | $ | 1,051 |
| | $ | 1,440 |
| | $ | 1,429 |
| PacifiCorp | $ | 1,133 | | | $ | 924 | | | $ | 1,072 | |
MidAmerican Funding | 550 |
| | 544 |
| | 551 |
| MidAmerican Funding | 416 | | | 454 | | | 549 | |
NV Energy | 607 |
| | 766 |
| | 774 |
| NV Energy | 621 | | | 649 | | | 655 | |
Northern Powergrid | 486 |
| | 488 |
| | 500 |
| Northern Powergrid | 543 | | | 421 | | | 472 | |
BHE Pipeline Group | 525 |
| | 473 |
| | 455 |
| BHE Pipeline Group | 1,516 | | | 779 | | | 572 | |
BHE Transmission | 313 |
| | 322 |
| | 92 |
| BHE Transmission | 339 | | | 316 | | | 323 | |
BHE Renewables | 325 |
| | 316 |
| | 256 |
| BHE Renewables | 329 | | | 291 | | | 336 | |
HomeServices | 214 |
| | 214 |
| | 212 |
| HomeServices | 505 | | | 511 | | | 222 | |
BHE and Other(1) | 1 |
| | (41 | ) | | (22 | ) | BHE and Other(1) | (75) | | | (54) | | | (51) | |
Total operating income | 4,072 |
| | 4,522 |
| | 4,247 |
| Total operating income | 5,327 | | | 4,291 | | | 4,150 | |
Interest expense | (1,838 | ) | | (1,841 | ) | | (1,854 | ) | Interest expense | (2,118) | | | (2,021) | | | (1,912) | |
Capitalized interest | 61 |
| | 45 |
| | 139 |
| Capitalized interest | 64 | | | 80 | | | 77 | |
Allowance for equity funds | 104 |
| | 76 |
| | 158 |
| Allowance for equity funds | 126 | | | 165 | | | 173 | |
Interest and dividend income | 113 |
| | 111 |
| | 120 |
| Interest and dividend income | 89 | | | 71 | | | 117 | |
(Losses) gains on marketable securities, net | (538 | ) | | 14 |
| | 10 |
| |
Gains (losses) on marketable securities, net | | Gains (losses) on marketable securities, net | 1,823 | | | 4,797 | | | (288) | |
Other, net | (9 | ) | | (420 | ) | | 30 |
| Other, net | (17) | | | 88 | | | 97 | |
Total income before income tax (benefit) expense and equity income (loss) | $ | 1,965 |
| | $ | 2,507 |
| | $ | 2,850 |
| |
Total income before income tax (benefit) expense and equity loss | | Total income before income tax (benefit) expense and equity loss | $ | 5,294 | | | $ | 7,471 | | | $ | 2,414 | |
|
| | | | | | | | | | | | | | | | | |
| |
| | | | | |
Interest expense: | | | | | |
PacifiCorp | $ | 430 | | | $ | 426 | | | $ | 401 | |
MidAmerican Funding | 319 | | | 322 | | | 302 | |
NV Energy | 206 | | | 227 | | | 229 | |
Northern Powergrid | 130 | | | 130 | | | 139 | |
BHE Pipeline Group | 143 | | | 74 | | | 52 | |
BHE Transmission | 155 | | | 148 | | | 157 | |
BHE Renewables | 158 | | | 166 | | | 174 | |
HomeServices | 4 | | | 11 | | | 25 | |
BHE and Other(1) | 573 | | | 517 | | | 433 | |
Total interest expense | $ | 2,118 | | | $ | 2,021 | | | $ | 1,912 | |
| | | | | |
Income tax (benefit) expense: | | | | | |
PacifiCorp | $ | (78) | | | $ | (75) | | | $ | 61 | |
MidAmerican Funding | (680) | | | (574) | | | (377) | |
NV Energy | 56 | | | 61 | | | 98 | |
Northern Powergrid | 192 | | | 96 | | | 59 | |
BHE Pipeline Group | 269 | | | 162 | | | 138 | |
BHE Transmission | 10 | | | 13 | | | 11 | |
BHE Renewables(2) | (753) | | | (602) | | | (325) | |
HomeServices | 138 | | | 138 | | | 51 | |
BHE and Other(1) | (286) | | | 1,089 | | | (314) | |
Total income tax (benefit) expense | $ | (1,132) | | | $ | 308 | | | $ | (598) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | Years Ended December 31, |
| Years Ended December 31, | | 2021 | | 2020 | | 2019 |
| 2018 | | 2017 | | 2016 | |
Interest expense: | | | | | | |
PacifiCorp | $ | 384 |
| | $ | 381 |
| | $ | 381 |
| |
MidAmerican Funding | 247 |
| | 237 |
| | 218 |
| |
NV Energy | 224 |
| | 233 |
| | 250 |
| |
Northern Powergrid | 141 |
| | 133 |
| | 136 |
| |
BHE Pipeline Group | 43 |
| | 43 |
| | 50 |
| |
BHE Transmission | 167 |
| | 169 |
| | 153 |
| |
BHE Renewables | 201 |
| | 204 |
| | 198 |
| |
HomeServices | 23 |
| | 7 |
| | 2 |
| |
BHE and Other(1) | 408 |
| | 434 |
| | 466 |
| |
Total interest expense | $ | 1,838 |
| | $ | 1,841 |
| | $ | 1,854 |
| |
| | | | | | |
Income tax (benefit) expense: | | | | | | |
Earnings on common shares: | | Earnings on common shares: | | | | | |
PacifiCorp | $ | 5 |
| | $ | 362 |
| | $ | 341 |
| PacifiCorp | $ | 889 | | | $ | 741 | | | $ | 773 | |
MidAmerican Funding | (262 | ) | | (202 | ) | | (139 | ) | MidAmerican Funding | 883 | | | 818 | | | 781 | |
NV Energy | 100 |
| | 221 |
| | 200 |
| NV Energy | 439 | | | 410 | | | 365 | |
Northern Powergrid | 61 |
| | 57 |
| | 22 |
| Northern Powergrid | 247 | | | 201 | | | 256 | |
BHE Pipeline Group | 119 |
| | 170 |
| | 163 |
| BHE Pipeline Group | 807 | | | 528 | | | 422 | |
BHE Transmission | 7 |
| | (124 | ) | | 26 |
| BHE Transmission | 247 | | | 231 | | | 229 | |
BHE Renewables(2) | (158 | ) | | (795 | ) | | (32 | ) | BHE Renewables(2) | 451 | | | 521 | | | 431 | |
HomeServices | 52 |
| | 49 |
| | 81 |
| HomeServices | 387 | | | 375 | | | 160 | |
BHE and Other(1) | (507 | ) | | (292 | ) | | (259 | ) | BHE and Other(1) | 1,319 | | | 3,092 | | | (467) | |
Total income tax (benefit) expense | $ | (583 | ) | | $ | (554 | ) | | $ | 403 |
| |
Total earnings on common shares | | Total earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | 2,950 | |
| | | | | | | | | | | |
Capital expenditures: | | | | | | Capital expenditures: | |
PacifiCorp | $ | 1,257 |
| | $ | 769 |
| | $ | 903 |
| PacifiCorp | $ | 1,513 | | | $ | 2,540 | | | $ | 2,175 | |
MidAmerican Funding | 2,332 |
| | 1,776 |
| | 1,637 |
| MidAmerican Funding | 1,912 | | | 1,836 | | | 2,810 | |
NV Energy | 503 |
| | 456 |
| | 529 |
| NV Energy | 749 | | | 675 | | | 657 | |
Northern Powergrid | 566 |
| | 579 |
| | 579 |
| Northern Powergrid | 742 | | | 682 | | | 602 | |
BHE Pipeline Group | 427 |
| | 286 |
| | 226 |
| BHE Pipeline Group | 1,128 | | | 659 | | | 687 | |
BHE Transmission | 270 |
| | 334 |
| | 466 |
| BHE Transmission | 279 | | | 372 | | | 247 | |
BHE Renewables | 817 |
| | 323 |
| | 719 |
| BHE Renewables | 225 | | | 95 | | | 122 | |
HomeServices | 47 |
| | 37 |
| | 20 |
| HomeServices | 42 | | | 36 | | | 54 | |
BHE and Other | 22 |
| | 11 |
| | 11 |
| BHE and Other | 21 | | | (130) | | | 10 | |
Total capital expenditures | $ | 6,241 |
| | $ | 4,571 |
| | $ | 5,090 |
| Total capital expenditures | $ | 6,611 | | | $ | 6,765 | | | $ | 7,364 | |
|
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Property, plant and equipment, net: | | | | | |
PacifiCorp | $ | 22,914 | | | $ | 22,430 | | | $ | 20,973 | |
MidAmerican Funding | 20,302 | | | 19,279 | | | 18,377 | |
NV Energy | 10,231 | | | 9,865 | | | 9,613 | |
Northern Powergrid | 7,572 | | | 7,230 | | | 6,606 | |
BHE Pipeline Group | 15,692 | | | 15,097 | | | 5,482 | |
BHE Transmission | 6,590 | | | 6,445 | | | 6,157 | |
BHE Renewables | 6,103 | | | 5,645 | | | 5,976 | |
HomeServices | 169 | | | 159 | | | 161 | |
BHE and Other | 243 | | | (22) | | | (40) | |
Total property, plant and equipment, net | $ | 89,816 | | | $ | 86,128 | | | $ | 73,305 | |
| | | | | |
Total assets: | | | | | |
PacifiCorp | $ | 27,615 | | | $ | 26,862 | | | $ | 24,861 | |
MidAmerican Funding | 25,352 | | | 23,530 | | | 22,664 | |
NV Energy | 15,239 | | | 14,501 | | | 14,128 | |
Northern Powergrid | 9,326 | | | 8,782 | | | 8,385 | |
BHE Pipeline Group | 20,434 | | | 19,541 | | | 6,100 | |
BHE Transmission | 9,476 | | | 9,208 | | | 8,776 | |
BHE Renewables | 11,829 | | | 12,004 | | | 9,961 | |
HomeServices | 4,574 | | | 4,955 | | | 3,846 | |
BHE and Other | 8,220 | | | 7,933 | | | 1,330 | |
Total assets | $ | 132,065 | | | $ | 127,316 | | | $ | 100,051 | |
| | | | | |
|
| | | | | | | | | | | |
| As of December 31, |
| 2018 | | 2017 | | 2016 |
Property, plant and equipment, net: | | | | | |
PacifiCorp | $ | 19,591 |
| | $ | 19,203 |
| | $ | 19,162 |
|
MidAmerican Funding | 16,171 |
| | 14,221 |
| | 12,835 |
|
NV Energy | 9,852 |
| | 9,770 |
| | 9,825 |
|
Northern Powergrid | 6,007 |
| | 6,075 |
| | 5,148 |
|
BHE Pipeline Group | 4,904 |
| | 4,587 |
| | 4,423 |
|
BHE Transmission | 5,824 |
| | 6,330 |
| | 5,810 |
|
BHE Renewables | 6,155 |
| | 5,637 |
| | 5,302 |
|
HomeServices | 141 |
| | 117 |
| | 78 |
|
BHE and Other | (50 | ) | | (69 | ) | | (74 | ) |
Total property, plant and equipment, net | $ | 68,595 |
| | $ | 65,871 |
| | $ | 62,509 |
|
| | | | | |
Total assets: | | | | | |
PacifiCorp | $ | 23,478 |
| | $ | 23,086 |
| | $ | 23,563 |
|
MidAmerican Funding | 20,029 |
| | 18,444 |
| | 17,571 |
|
NV Energy | 14,119 |
| | 13,903 |
| | 14,320 |
|
Northern Powergrid | 7,427 |
| | 7,565 |
| | 6,433 |
|
BHE Pipeline Group | 5,511 |
| | 5,134 |
| | 5,144 |
|
BHE Transmission | 8,424 |
| | 9,009 |
| | 8,378 |
|
BHE Renewables | 8,666 |
| | 7,687 |
| | 7,010 |
|
HomeServices | 2,797 |
| | 2,722 |
| | 1,776 |
|
BHE and Other | 1,738 |
| | 2,658 |
| | 1,245 |
|
Total assets | $ | 92,189 |
| | $ | 90,208 |
| | $ | 85,440 |
|
| | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenue by country: | | | | | |
United States | $ | 18,014 |
| | $ | 16,916 |
| | $ | 15,895 |
|
United Kingdom | 1,017 |
| | 948 |
| | 995 |
|
Canada | 710 |
| | 699 |
| | 506 |
|
Philippines and other | 46 |
| | 51 |
| | 26 |
|
Total operating revenue by country | $ | 19,787 |
| | $ | 18,614 |
| | $ | 17,422 |
|
| | | | | |
Income before income tax (benefit) expense and equity income (loss) by country: | | | | |
United States | $ | 1,425 |
| | $ | 1,927 |
| | $ | 2,264 |
|
United Kingdom | 307 |
| | 313 |
| | 382 |
|
Canada | 155 |
| | 167 |
| | 135 |
|
Philippines and other | 78 |
| | 100 |
| | 69 |
|
Total income before income tax (benefit) expense and equity (loss) income by country: | $ | 1,965 |
| | $ | 2,507 |
| | $ | 2,850 |
|
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue by country: | | | | | |
United States | $ | 23,215 | | | $ | 19,254 | | | $ | 18,108 | |
United Kingdom | 1,188 | | | 1,022 | | | 1,011 | |
Canada | 719 | | | 653 | | | 706 | |
Other | 28 | | | 23 | | | 19 | |
Total operating revenue by country | $ | 25,150 | | | $ | 20,952 | | | $ | 19,844 | |
| | | | | |
Income before income tax (benefit) expense and equity loss by country: | | | | |
United States | $ | 4,650 | | | $ | 6,954 | | | $ | 1,866 | |
United Kingdom | 454 | | | 338 | | | 326 | |
Canada | 181 | | | 173 | | | 178 | |
Other | 9 | | | 6 | | | 44 | |
Total income before income tax (benefit) expense and equity loss by country: | $ | 5,294 | | | $ | 7,471 | | | $ | 2,414 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Property, plant and equipment, net by country: | | | | | |
United States | $ | 75,774 | | | $ | 72,583 | | | $ | 60,634 | |
United Kingdom | 7,487 | | | 7,134 | | | 6,504 | |
Canada | 6,547 | | | 6,401 | | | 6,157 | |
Other | 8 | | | 10 | | | 10 | |
Total property, plant and equipment, net by country | $ | 89,816 | | | $ | 86,128 | | | $ | 73,305 | |
|
| | | | | | | | | | | |
| As of December 31, |
| 2018 | | 2017 | | 2016 |
Property, plant and equipment, net by country: | | | | | |
United States | $ | 56,870 |
| | $ | 53,579 |
| | $ | 51,671 |
|
United Kingdom | 5,895 |
| | 5,953 |
| | 5,020 |
|
Canada | 5,817 |
| | 6,323 |
| | 5,803 |
|
Philippines and other | 13 |
| | 16 |
| | 15 |
|
Total property, plant and equipment, net by country | $ | 68,595 |
| | $ | 65,871 |
| | $ | 62,509 |
|
(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate to other corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
| |
(1) | The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate to other corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations. |
| |
(2) | Income tax (benefit) expense includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE. |
(2)Income tax (benefit) expense includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 20182021 and 20172020 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE | | | | | | | | | | |
| | | MidAmerican | | NV | | Northern | | Pipeline | | BHE | | BHE | | | | | | |
| PacifiCorp | | Funding | | Energy | | Powergrid | | Group | | Transmission | | Renewables | | HomeServices | | | | Total |
| | | | | | | | | | | | | | | | | | | |
December 31, 2019 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 978 | | | $ | 73 | | | $ | 1,520 | | | $ | 95 | | | $ | 1,456 | | | | | $ | 9,722 | |
Acquisitions | — | | | — | | | — | | | — | | | 1,730 | | | — | | | — | | | 1 | | | | | 1,731 | |
Foreign currency translation | — | | | — | | | — | | | 22 | | | — | | | 31 | | | — | | | — | | | | | 53 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
December 31, 2020 | 1,129 | | | 2,102 | | | 2,369 | | | 1,000 | | | 1,803 | | | 1,551 | | | 95 | | | 1,457 | | | | | 11,506 | |
Acquisitions | — | | | — | | | — | | | — | | | 11 | | | — | | | — | | | 129 | | | | | 140 | |
Foreign currency translation | — | | | — | | | — | | | (8) | | | — | | | 12 | | | — | | | — | | | | | 4 | |
| | | | | | | | | | | | | | | | | | | |
December 31, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 992 | | | $ | 1,814 | | | $ | 1,563 | | | $ | 95 | | | $ | 1,586 | | | | | $ | 11,650 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE | | | | | | | | BHE | | |
| | | MidAmerican | | NV | | Northern | | Pipeline | | BHE | | BHE | | Home- | | and | | |
| PacifiCorp | | Funding | | Energy | | Powergrid | | Group | | Transmission | | Renewables | | Services | | Other | | Total |
| | | | | | | | | | | | | | | | | | | |
December 31, 2016 | $ | 1,129 |
| | $ | 2,102 |
| | $ | 2,369 |
| | $ | 930 |
| | $ | 75 |
| | $ | 1,470 |
| | $ | 95 |
| | $ | 840 |
| | $ | — |
| | $ | 9,010 |
|
Acquisitions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 508 |
| | — |
| | 508 |
|
Foreign currency translation | — |
| | — |
| | — |
| | 61 |
| | — |
| | 101 |
| | — |
| | — |
| | — |
| | 162 |
|
Other | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) |
December 31, 2017 | 1,129 |
| | 2,102 |
| | 2,369 |
| | 991 |
| | 73 |
| | 1,571 |
| | 95 |
| | 1,348 |
| | — |
| | 9,678 |
|
Acquisitions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | 79 |
|
Foreign currency translation | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (123 | ) | | — |
| | — |
| | — |
| | (162 | ) |
December 31, 2018 | $ | 1,129 |
| | $ | 2,102 |
| | $ | 2,369 |
| | $ | 952 |
| | $ | 73 |
| | $ | 1,448 |
| | $ | 95 |
| | $ | 1,427 |
| | $ | — |
| | $ | 9,595 |
|
PacifiCorp and its subsidiaries
Consolidated Financial Section
| |
Item 6. | Selected Financial Data |
The following table sets forth PacifiCorp's selected consolidated historical financial data, which should be read in conjunction with the information in Item 7 of this Form 10-K and with PacifiCorp's historical Consolidated Financial Statements and notes thereto in Item 8 of this Form 10-K. The selected consolidated historical financial data has been derived from PacifiCorp's audited historical Consolidated Financial Statements and notes thereto (in millions).
|
| | | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | | | | | | | |
Consolidated Statement of Operations Data: | | | | | | | | | |
Operating revenue | $ | 5,026 |
| | $ | 5,237 |
| | $ | 5,201 |
| | $ | 5,232 |
| | $ | 5,252 |
|
Operating income(1) | 1,051 |
| | 1,440 |
| | 1,428 |
| | 1,347 |
| | 1,309 |
|
Net income | 738 |
| | 768 |
| | 763 |
| | 695 |
| | 698 |
|
|
| | | | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | | | | | | | |
Consolidated Balance Sheet Data: | | | | | | | | | |
Total assets(2)(3) | $ | 22,313 |
| | $ | 21,920 |
| | $ | 22,394 |
| | $ | 22,367 |
| | $ | 22,205 |
|
Short-term debt | 30 |
| | 80 |
| | 270 |
| | 20 |
| | 20 |
|
Current portion of long-term debt and | | | | | | | | | |
capital lease obligations | 352 |
| | 588 |
| | 58 |
| | 68 |
| | 134 |
|
Long-term debt and capital lease obligations, | | | | | | | | | |
excluding current portion(3) | 6,684 |
| | 6,437 |
| | 7,021 |
| | 7,078 |
| | 6,885 |
|
Total shareholders' equity | 7,845 |
| | 7,555 |
| | 7,390 |
| | 7,503 |
| | 7,756 |
|
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
| |
(1) | In January 2018, PacifiCorp retrospectively adopted Accounting Standards Update No. 2017-07, which resulted in the reclassification of amounts other than the service cost for pension and other postretirement benefit plans to Other, net of a $22 million benefit as of December 31, 2017, a $2 million cost as of December 31, 2016, a $7 million cost as of December 31, 2015, and a $9 million cost as of December 31, 2014, with a corresponding increase or reduction to operating expenses. |
| |
(2) | In December 2015, PacifiCorp retrospectively adopted Accounting Standards Update No. 2015-17, which resulted in the reclassification of current deferred income tax assets in the amount of $28 million as of December 31, 2014 as a reduction in noncurrent deferred income tax liabilities. |
| |
(3) | In December 2015, PacifiCorp retrospectively adopted Accounting Standards Update No. 2015-03, which resulted in the reclassification of certain deferred debt issuance costs previously recognized within other assets in the amount of $34 million as of December 31, 2014 as a reduction in long-term debt. |
| |
Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Item 6 of this Form 10-K and with PacifiCorp's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2018,2021, was $738$888 million, an increase of $149 million, or 20%, compared to 2020, primarily due to higher utility gross margin (excluding $231 million of decreases fully offset in depreciation, operating, other income/expense and income tax expense due to prior year regulatory adjustments); lower operations and maintenance expense primarily due to prior year costs associated with the 2020 Wildfires and changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met; and favorable income tax expense from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking; partially offset by higher depreciation and amortization expense (excluding $376 million of decreases offset in operating revenue and income tax expense due to prior year regulatory adjustments) from the impacts of the depreciation study for which rates became effective January 2021 and higher plant in-service; and lower allowances for equity and borrowed funds used during construction. Utility margin increased $145 million (excluding the $231 million of fully offsetting decreases) primarily due to the higher retail, wheeling and wholesale revenue; higher deferred net power costs; and lower purchased electricity volumes; partially offset by higher purchased electricity prices; and higher natural gas- and coal-fueled generation costs. Retail customer volumes increased 3.1% due to increase in customer usage, increase in the average number of customers and favorable impacts of weather. Energy generated increased 10% for 2021 compared to 2020 primarily due higher wind-powered, natural gas-fueled and coal-fueled generation, partially offset by lower hydroelectric-powered generation. Wholesale electricity sales volumes decreased 3% and purchased electricity volumes decreased 17%.
Net income for the year ended December 31, 2020 was $739 million, a decrease of $30$32 million, or 4%, compared to 2017,2019, primarily due to lower utility margincosts associated with the 2020 Wildfires and the Klamath Hydroelectric Project of $198 million,$169 million; higher depreciation and amortizationnet interest expense of $183$36 million due to accelerated depreciation for Utah's share of certain thermal plant units of $174 million ($170 million offset in income tax expensefrom higher long-term debt and $4 million offset in revenue), higher plant in-service, andlower cash balances; higher pension and other postretirement expensecosts of $13 million, primarily due to a pension settlement charge,million; and higher property taxes of $10 million; partially offset by a decrease inlower income tax expense of $355$99 million and(excluding $37 million fully offset primarily in depreciation expense) primarily driven by higher allowancePTCs substantially due to repowered wind-powered generating facilities and lower pre-tax income; higher utility margin of $47 million (excluding $231 million of increases fully offset in depreciation, operating, other income/expense and income tax expense as a result of regulatory adjustments as ordered by the UPSC, the OPUC and the IPUC); higher allowances for equity and borrowed funds used during construction of $22$38 million; and prior year costs associated with the early retirement of a coal-fueled generation unit totaling $24 million. Utility margin decreasedincreased primarily due to lower coal-fueled generation volumes, lower purchased electricity prices, higher average retail rates including the impact of theand lower federal tax rate due to the 2017 Tax Reform of $152 million, higher natural gas-fueled generation volumes, lower average wholesale prices, higher purchased electricity from higher prices, and lower retail customer volumes,costs, partially offset by higherlower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower natural gas prices, higher wholesaleretail customer volumes and lower coal-fueled generationhigher purchased electricity volumes. Income tax expense decreased primarily due to lower federal tax rate due to the impact of 2017 Tax Reform, and amortization of a portion of Utah's allocated excess deferred income taxes used to accelerate depreciation of certain thermal plant units as ordered by the UPSC. Retail customer volumes decreased by 0.2%1.4% primarily due to impacts of weather on the residentialCOVID-19, which resulted in lower industrial and commercial customer volumes, lowerusage and higher residential customer usage, in all states except Utah and lower industrial usage in Oregon, Washington and Utah, partially offset by an increase in the average number of commercial and residential customers across the service territory, higher commercial and residential usage in Utah, higher irrigation usage, and higher industrial usage in Wyoming and Idaho. Energy generated increased 2% for 2018 compared to 2017 primarily due to higher natural gas-fueled and wind-power generation, partially offset by lower hydroelectric and coal-fueled generation. Wholesale electricity sales volumes increased 15% and purchased electricity volumes decreased 4%.
Net income for the year ended December 31, 2017, was $768 million, an increase of $5 million, or 1%, compared to 2016, which includes $6 million of income from the 2017 Tax Reform. Excluding the impact of 2017 Tax Reform, adjusted net income for the year ended December 31, 2017, was $762 million, a decrease of $1 million compared to 2016. Net income decreased primarily due to higher depreciation and amortization of $26 million from additional plant placed in-service, lower AFUDC of $11 million, higher property and other taxes of $7 million and higher operations and maintenance expenses of $3 million, excluding the impact of DSM program expense of $55 million (offset in operating revenue), partially offset by higher utility margin of $72 million, excluding the impact of DSM program revenue (offset in operations and maintenance expense) of $55 million. Utility margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue from higher volumes and short-term market prices, and higher wheeling revenues, partially offset by higher purchased electricity costs, lower average retail rates, and higher coal costs. Retail customer volumes increased 1.7% due to impacts of weather across the service territory, higher commercial usage, and an increase in the average number of residential and commercial customers primarily in Utah and Oregon, partially offset by lower residential customers' usage in Utah and Oregon, and lower irrigation usage.the favorable impact of weather. Energy generated decreased 2%4% for 20172020 compared to 20162019 primarily due to lower natural gas-fueled and wind-powercoal-fueled generation, partially offset by higher coal-fueled,wind and hydroelectrichydroelectric-powered generation. Wholesale electricity sales volumes increased 9%decreased 4% and purchased electricity volumes increased 23%9%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
PacifiCorp's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in PacifiCorp's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions) for the years ended December 31:31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin: | | | | | | | | | | | | | |
Operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | 5 | % |
Cost of fuel and energy | 1,831 | | | 1,790 | | | 41 | | 2 | | | 1,790 | | | 1,795 | | | (5) | | — | |
Utility margin | 3,465 | | | 3,551 | | | (86) | | (2) | | | 3,551 | | | 3,273 | | | 278 | | 8 | |
Operations and maintenance | 1,031 | | | 1,209 | | | (178) | | (15) | | | 1,209 | | | 1,048 | | | 161 | | 15 | |
Depreciation and amortization | 1,088 | | | 1,209 | | | (121) | | (10) | | | 1,209 | | | 954 | | | 255 | | 27 | |
Property and other taxes | 213 | | | 209 | | | 4 | | 2 | | | 209 | | | 199 | | | 10 | | 5 | |
Operating income | $ | 1,133 | | | $ | 924 | | | $ | 209 | | 23 | % | | $ | 924 | | | $ | 1,072 | | | $ | (148) | | (14) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Utility margin: | | | | | | | | | | | | | |
Operating revenue | $ | 5,026 |
| | $ | 5,237 |
| | $ | (211 | ) | (4 | )% | | $ | 5,237 |
| | 5,201 |
| | $ | 36 |
| 1 | % |
Cost of fuel and energy | 1,757 |
| | 1,770 |
| | (13 | ) | (1 | ) | | 1,770 |
| | 1,751 |
| | 19 |
| 1 |
|
Utility margin | 3,269 |
| | 3,467 |
| | (198 | ) | (6 | ) | | 3,467 |
| | 3,450 |
| | 17 |
| — |
|
Operations and maintenance | 1,038 |
| | 1,034 |
| | 4 |
| — |
| | 1,034 |
| | 1,062 |
| | (28 | ) | (3 | ) |
Depreciation and amortization | 979 |
| | 796 |
| | 183 |
| 23 |
| | 796 |
| | 770 |
| | 26 |
| 3 |
|
Property and other taxes | 201 |
| | 197 |
| | 4 |
| 2 |
| | 197 |
| | 190 |
| | 7 |
| 4 |
|
Operating income | $ | 1,051 |
| | $ | 1,440 |
| | $ | (389 | ) | (27 | ) | | $ | 1,440 |
| | $ | 1,428 |
| | $ | 12 |
| 1 |
|
Utility Margin
A comparison of PacifiCorp's key operating results related to utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
| | | | | | | | | | | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | | | |
Operating revenue | | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | | 5 | % |
Cost of fuel and energy | | 1,831 | | | 1,790 | | | 41 | | | 2 | | | 1,790 | | | 1,795 | | | (5) | | | — | |
Utility margin | | $ | 3,465 | | | $ | 3,551 | | | $ | (86) | | | (2) | % | | $ | 3,551 | | | $ | 3,273 | | | $ | 278 | | | 8 | % |
| | | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | | |
Residential | | 17,905 | | | 17,150 | | | 755 | | | 4 | % | | 17,150 | | | 16,668 | | | 482 | | | 3 | % |
Commercial(1) | | 18,839 | | | 17,727 | | | 1,112 | | | 6 | | | 17,727 | | | 18,151 | | | (424) | | | (2) | |
Industrial(1) | | 17,909 | | | 18,039 | | | (130) | | | (1) | | | 18,039 | | | 19,049 | | | (1,010) | | | (5) | |
Other(1) | | 1,621 | | | 1,644 | | | (23) | | | (1) | | | 1,644 | | | 1,475 | | | 169 | | | 11 | |
Total retail | | 56,274 | | | 54,560 | | | 1,714 | | | 3 | | | 54,560 | | | 55,343 | | | (783) | | | (1) | |
Wholesale | | 5,113 | | | 5,249 | | | (136) | | | (3) | | | 5,249 | | | 5,480 | | | (231) | | | (4) | |
Total sales | | 61,387 | | | 59,809 | | | 1,578 | | | 3 | % | | 59,809 | | | 60,823 | | | (1,014) | | | (2) | % |
| | | | | | | | | | | | | | | | |
Average number of retail customers | | | | | | | | | | | | | | | | |
(in thousands) | | 2,003 | | | 1,967 | | | 36 | | | 2 | % | | 1,967 | | | 1,933 | | | 34 | | | 2 | % |
| | | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | | |
Retail | | $ | 86.08 | | | $ | 90.59 | | | $ | (4.51) | | | (5) | % | | $ | 90.59 | | | $ | 84.80 | | | $ | 5.79 | | | 7 | % |
Wholesale | | $ | 37.90 | | | $ | 35.56 | | | $ | 2.34 | | | 7 | % | | $ | 35.56 | | | $ | 35.21 | | | $ | 0.35 | | | 1 | % |
| | | | | | | | | | | | | | | | |
Heating degree days | | 9,914 | | | 10,155 | | | (241) | | | (2) | % | | 10,155 | | | 11,143 | | | (988) | | | (9) | % |
Cooling degree days | | 2,431 | | | 2,111 | | | 320 | | | 15 | % | | 2,111 | | | 1,773 | | | 338 | | | 19 | % |
| | | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | | |
Coal | | 31,566 | | | 30,636 | | | 930 | | | 3 | % | | 30,636 | | | 34,510 | | | (3,874) | | | (11) | % |
Natural gas | | 13,323 | | | 12,045 | | | 1,278 | | | 11 | | | 12,045 | | | 12,058 | | | (13) | | | — | |
Wind(2) | | 6,686 | | | 3,769 | | | 2,917 | | | 77 | | | 3,769 | | | 2,266 | | | 1,503 | | | 66 | |
Hydroelectric and other(2) | | 3,010 | | | 3,223 | | | (213) | | | (7) | | | 3,223 | | | 2,961 | | | 262 | | | 9 | |
Total energy generated | | 54,585 | | | 49,673 | | | 4,912 | | | 10 | | | 49,673 | | | 51,795 | | | (2,122) | | | (4) | |
Energy purchased | | 11,601 | | | 14,054 | | | (2,453) | | | (17) | | | 14,054 | | | 12,906 | | | 1,148 | | | 9 | |
Total | | 66,186 | | | 63,727 | | | 2,459 | | | 4 | % | | 63,727 | | | 64,701 | | | (974) | | | (2) | % |
| | | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | | |
Energy generated(3) | | $ | 18.05 | | | $ | 18.74 | | | $ | (0.69) | | | (4) | % | | $ | 18.74 | | | $ | 19.36 | | | $ | (0.62) | | | (3) | % |
Energy purchased | | $ | 66.93 | | | $ | 47.60 | | | $ | 19.33 | | | 41 | % | | $ | 47.60 | | | $ | 54.20 | | | $ | (6.60) | | | (12) | % |
(1) GWh amounts are net of energy used by the related generating facilities.
(2)All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
| | | | | | | | | | | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | | | |
Operating revenue | | $ | 5,026 |
| | $ | 5,237 |
| | $ | (211 | ) | | (4 | )% | | $ | 5,237 |
| | $ | 5,201 |
| | $ | 36 |
| | 1 | % |
Cost of fuel and energy | | 1,757 |
| | 1,770 |
| | (13 | ) | | (1 | ) | | 1,770 |
| | 1,751 |
| | 19 |
| | 1 |
|
Utility margin | | $ | 3,269 |
| | $ | 3,467 |
| | $ | (198 | ) | | (6 | ) | | $ | 3,467 |
| | $ | 3,450 |
| | $ | 17 |
| | — |
|
| | | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | | |
Residential | | 16,227 |
| | 16,625 |
| | (398 | ) | | (2 | )% | | 16,625 |
| | 16,058 |
| | 567 |
| | 4 | % |
Commercial(1) | | 18,078 |
| | 17,726 |
| | 352 |
| | 2 |
| | 17,726 |
| | 16,857 |
| | 869 |
| | 5 |
|
Industrial, irrigation and other(1) | | 20,810 |
| | 20,899 |
| | (89 | ) | | — |
| | 20,899 |
| | 21,403 |
| | (504 | ) | | (2 | ) |
Total retail | | 55,115 |
| | 55,250 |
| | (135 | ) | | — |
| | 55,250 |
| | 54,318 |
| | 932 |
| | 2 |
|
Wholesale | | 8,309 |
| | 7,218 |
| | 1,091 |
| | 15 |
| | 7,218 |
| | 6,641 |
| | 577 |
| | 9 |
|
Total sales | | 63,424 |
| | 62,468 |
| | 956 |
| | 2 |
| | 62,468 |
| | 60,959 |
| | 1,509 |
| | 2 |
|
| | | | | | | | | | | | | | | | |
Average number of retail customers | | | | | | | | | | | | | | | | |
(in thousands) | | 1,900 |
| | 1,867 |
| | 33 |
| | 2 | % | | 1,867 |
| | 1,841 |
| | 26 |
| | 1 | % |
| | | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | | |
Retail | | $ | 84.43 |
| | $ | 87.78 |
| | $ | (3.35 | ) | | (4 | )% | | $ | 87.78 |
| | $ | 89.55 |
| | $ | (1.77 | ) | | (2 | )% |
Wholesale | | $ | 22.56 |
| | $ | 28.56 |
| | $ | (6.00 | ) | | (21 | )% | | $ | 28.56 |
| | $ | 26.46 |
| | $ | 2.10 |
| | 8 | % |
| | | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | | |
Coal | | 36,481 |
| | 37,362 |
| | (881 | ) | | (2 | )% | | 37,362 |
| | 36,578 |
| | 784 |
| | 2 | % |
Natural gas | | 10,555 |
| | 7,447 |
| | 3,108 |
| | 42 |
| | 7,447 |
| | 9,884 |
| | (2,437 | ) | | (25 | ) |
Hydroelectric(2) | | 3,263 |
| | 4,731 |
| | (1,468 | ) | | (31 | ) | | 4,731 |
| | 3,843 |
| | 888 |
| | 23 |
|
Wind and other | | 3,205 |
| | 2,890 |
| | 315 |
| | 11 |
| | 2,890 |
| | 3,253 |
| | (363 | ) | | (11 | ) |
Total energy generated | | 53,504 |
| | 52,430 |
| | 1,074 |
| | 2 |
| | 52,430 |
| | 53,558 |
| | (1,128 | ) | | (2 | ) |
Energy purchased | | 13,579 |
| | 14,076 |
| | (497 | ) | | (4 | ) | | 14,076 |
| | 11,429 |
| | 2,647 |
| | 23 |
|
Total | | 67,083 |
| | 66,506 |
| | 577 |
| | 1 |
| | 66,506 |
| | 64,987 |
| | 1,519 |
| | 2 |
|
| | | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | | |
Energy generated(3) | | $ | 18.91 |
| | $ | 19.14 |
| | $ | (0.23 | ) | | (1 | )% | | $ | 19.14 |
| | $ | 19.27 |
| | $ | (0.13 | ) | | (1 | )% |
Energy purchased | | $ | 48.23 |
| | $ | 43.25 |
| | $ | 4.98 |
| | 12 | % | | $ | 43.25 |
| | $ | 44.64 |
| | $ | (1.39 | ) | | (3 | )% |
| |
(1) | GWh amounts are net of energy used by the related generating facilities. |
| |
(2) | All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities. |
| |
(3) | The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities. |
Year Ended December 31, 20182021 Compared to Year Ended December 31, 20172020
Utility margin decreased $198$86 million (including the $231 million of fully offsetting decreases) for 20182021 compared to 20172020 primarily due to:
•$180 million of lower retail revenue primarily due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $152 million;
$59 million of higher natural gas-fueled generation volumes;
$42 million of lower average wholesale prices;
$41111 million of higher purchased electricity costs due to higher prices; andaverage prices, partially offset by lower volumes;
•$1799 million of lower retail revenue primarily due to $234 million fully offset in depreciation expense, income tax expense, fuel expense, and other income (expense) due to accelerated depreciation of certain coal-fueled units in Utah and Oregon and recognition of certain Utah regulatory balances in the prior year, and lower average retail prices, partially offset by higher retail customer volumes. Retail customer volumes increased 3.1% due to an increase in residential and commercial customer usage, increase in the average number of customers and favorable impacts of weather, primarily in Oregon, Washington and Idaho;
•$88 million of higher natural gas-fueled generation costs primarily due to higher average prices and higher volumes; and
•$34 million of lower other revenue due to prior year recognition of prior OATT revenue related deferrals in Oregon used to accelerate the depreciation of certain retired wind equipment as a result of the 2020 Oregon RAC settlement (offset in depreciation expense).
The decreases above were partially offset by:
•$141 million primarily from higher deferred net power costs in accordance with established adjustment mechanisms;
•$43 million of favorable wheeling activities;
•$33 million of lower coal-fueled generation costs primarily due to $37 million of accelerated recognition of certain Utah regulatory balances associated with the 2015 Utah mine disposition and certain Cholla Unit 4 related closure costs in Oregon and Idaho (offset in income tax expense) in the prior year and lower prices, partially offset by higher volumes;
•$19 million of higher other revenue primarily due to higher REC, fly ash and by-product revenues; and
•$7 million of higher wholesale revenue due to higher average wholesale market prices, partially offset by lower wholesale volumes.
Operations and maintenance decreased $178 million, or 15%, for 2021 compared to 2020 primarily due to prior year estimated losses associated with the 2020 Wildfires of $136 million, net of expected insurance recoveries, changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met, lower thermal plant maintenance expense and lower labor expenses, partially offset by higher wind plant and distribution maintenance and higher legal and insurance expenses associated with the 2020 Wildfires.
Depreciation and amortization decreased $121 million, or 10%, for 2021 compared to 2020 primarily due to prior year accelerated depreciation of $376 million as a result of regulatory adjustments ordered by the UPSC, the OPUC and the IPUC (fully offset in retail revenue, other revenue, and income tax expense), including accelerated depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment as a result the 2020 Oregon RAC settlement, partially offset by the impacts of the depreciation study for which rates became effective January 1, 2021 of approximately $158 million and higher plant in-service balances.
Property and other taxes increased $4 million, or 2%, for 2021 compared to 2020 primarily due to higher property taxes in Oregon and Wyoming, partially offset by lower property taxes in Utah and Washington.
Interest expense increased $4 million, or 1%, for 2021 compared to 2020 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds decreased $72 million, or 49%, for 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.
Interest and dividend income increased$14 million, or 140%, for 2021 compared to 2020 primarily due to higher carrying charges on DSM regulatory assets in the current year.
Income tax benefit increased $4 million, or 5%, for 2021 compared to 2020. The effective tax rate was (10)% and (11)% for 2021 and 2020, respectively. The effective tax rate increased primarily as a result of lower effects of ratemaking associated with excess deferred income tax amortization, offset by increased PTCs from PacifiCorp's new wind-powered generating facilities in the current year. In 2020, $118 million of excess deferred income taxes was amortized pursuant to regulatory orders from Utah, Oregon and Idaho, whereby portions of excess deferred income taxes were used to accelerate depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment or offset other regulatory balances for these jurisdictions.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Utility margin increased $278 million for 2020 compared to 2019 primarily due to:
•$249 million increase in retail revenue, including $234 million fully offset in depreciation expense and income tax expense due to accelerated depreciation of certain coal-fueled units in Utah and Oregon and recognition of certain Utah regulatory balances and higher average retail prices, partially offset by lower retail customer volumes. Retail customer volumes decreased 0.2%1.4% primarily due to the unfavorable impacts of weather on the residentialCOVID-19, which resulted in lower industrial and commercial customer volumes, lowerusage and higher residential customer usage, in all states except Utah, and lower industrial usage in Oregon, Washington and Utah, partially offset by an increase in the average number of residential and commercial customers and residential customers across the service territory, higher commercialfavorable impact of weather;
•$49 million of lower coal-fueled generation costs primarily due to lower volumes of $78 million, partially offset by $37 million of accelerated recognition of certain Utah regulatory balances associated with the 2015 Utah mine disposition and residential usagecertain Cholla Unit 4 related closure costs in Utah, higher irrigation usage,Oregon and Idaho (offset in income tax expense) and higher industrial usageprices of $9 million;
•$34 million of higher other revenue due to recognition of prior OATT revenue related deferrals in WyomingOregon used to accelerate the depreciation of certain retired wind equipment as a result of the 2020 Oregon RAC settlement (offset in depreciation expense);
•$31 million of lower purchased electricity costs, primarily due to lower average market prices, partially offset by higher volumes; and Idaho.
•$24 million of lower natural gas-fueled generation costs primarily due to lower average prices and lower volumes.
The decreasesincreases above were partially offset by:
•$70106 million primarily from lower deferrals and higher amortization of higher netprevious deferrals of incurred net power costs in accordance with established adjustment mechanisms;mechanisms.
$33 million of lower natural gas costs from lower average prices;
$23 million of higher wholesale revenue due to higher volumes; and
$20 million of lower coal costs due to lower volumes.
Operations and maintenance increased $4$161 million, or 15%, for 20182020 compared to 20172019 primarily due to reserves accrued for 2018costs associated with the 2020 Wildfires of $136 million, net of expected insurance deductibles for third-party property damagerecoveries, and costs associated with the Klamath Hydroelectric Project of $33 million, higher vegetation management and wildfire mitigation costs of $26 million and increased bad debt expense of $5 million, partially offset by prior year costs associated with the early retirement of Cholla Unit 4 of $24 million and lower employee related expenses of $7 million and increased maintenance costs partially offset by favorable labor costs.as a result of COVID-19.
Depreciation and amortization increased $183$255 million, or 23%27%, for 20182020 compared to 20172019 primarily due to $174 million ofcurrent year accelerated depreciation for Utah's share of certain thermal plant units$376 million as a result of regulatory adjustments ordered by the UPSC, the OPUC and the IPUC (fully offset in retail revenue, other revenue, and income tax expense), including accelerated depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment as a result the 2020 Oregon RAC settlement, partially offset by prior year accelerated depreciation of $120 million (offset in income tax reform docketexpense) on Oregon's share of certain retired wind equipment due to offset excess deferred incomerepowering as a result of the 2019 Oregon RAC settlement.
Property and other taxes benefits owed to customers, and higher plant-in-service.
Taxes, other than income taxes increased $4$10 million, or 2%5%, for 20182020 compared to 20172019 primarily due to higher assessed property values.taxes in Oregon and Utah.
Interest expense increased $25 million, or 6%, for 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity fundsincreased $22$38 million, or 71%35%, for 20182020 compared to 20172019 primarily due to a prior year true-up that reduced AFUDC rates by $13 million and higher qualified construction work-in-progress balances.
Other, netInterest and dividend income decreased $15$11 million, or 39%52%, for 20182020 compared to 20172019 primarily due to a pension settlement charge oflower average interest rates in the current year.
Other, net decreased $22 million, partially offset by lower non-service cost components ofor 69% for 2020 compared to 2019 primarily due to higher pension and other postretirement expensespost retirement costs of $9 million.$13 million and costs associated with the recognition of Utah's share of the post retirement settlement loss associated with the 2015 Utah mine disposition (offset in income tax expense).
Income tax (benefit) expense decreased $355$136 million or 99%,to a benefit of $75 million for 20182020 compared to 2017 and thean expense of $61 million for 2019. The effective tax rate was 1%(11)% and 32%7% for 20182020 and 2017,2019, respectively. The effective tax rate decreased primarily as a result of the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, and thehigher amortization of $127excess deferred income taxes in 2020 and higher PTCs. In 2020, $118 million of Utah'sexcess deferred income taxes was amortized pursuant to regulatory orders from Utah, Oregon and Idaho, whereby portions of excess deferred income taxes were used to accelerate depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment or offset other regulatory balances for these jurisdictions. In 2019, $91 million of Oregon's allocated excess deferred income taxes was amortized pursuant to a 2017 Tax Reform settlement approved by the UPSC,2019 Oregon RAC proceeding, whereby a portion of Utah'sOregon's allocated excess deferred incomesincome taxes was used to accelerate depreciation on Utah'sfor Oregon's share of certain thermal plant units.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Utility margin increased $17 million for 2017 compared to 2016 primarily due to:
$105 million of higher retail revenuesretired wind equipment due to increased customer volumes of 1.7% due to impacts of weather across the service territory, higher commercial usage, an increase in the average number of residential and commercial customers primarily in Utah and Oregon, partially offset by lower residential usage in Utah and Oregon and lower irrigation usage;repowering.
$54 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;
$40 million of lower natural gas costs primarily due to lower volumes and prices in 2017;
$30 million of higher wholesale revenue due to higher volumes and short-term market prices;
$20 million of lower coal costs due to prior year charges related to damaged longwall mining equipment; and
$12 million of higher wheeling revenue, primarily due to increased volumes and short-term prices.
The increases above were partially offset by:
$99 million of higher purchased electricity costs due to higher volumes;
$64 million of lower average retail rates, primarily due to product mix;
$55 million of lower DSM program revenue (offset in operations and maintenance expense), primarily driven by the recently implemented Utah Sustainable Transportation and Energy Plan ("STEP") program; and
$31 million of higher coal costs due to higher volumes and prices.
Operations and maintenance decreased $28 million, or 3%, for 2017 compared to 2016 primarily due to a decrease in DSM program expense (offset in revenues) of $55 million driven by the establishment of the Utah STEP program and lower pension expense due to plan changes effective in 2017, partially offset by higher injury and damage expenses, primarily due to prior year accrual for insurance proceeds and current year settlements, and higher labor costs for storm damage restoration. In January 2018, PacifiCorp retrospectively adopted Accounting Standards Update No. 2017-07, which resulted in the reclassification of non-service cost amounts for pension and other postretirement benefit plans from Operations and Maintenance expense to Other, net of $22 million benefit as of December 31, 2017, and $2 million cost as of December 31, 2016.
Depreciation and amortization increased $26 million, or 3%, for 2017 compared to 2016 primarily due to higher plant in-service.
Taxes, other than income taxes increased $7 million, or 4%, for 2017 compared to 2016 primarily due to higher assessed property values.
Allowance for borrowed and equity funds decreased $11 million, or 26%, for 2017 compared to 2016 primarily due to a true-up of AFUDC rates.
Income tax expense increased $20 million, or 6%, for 2017 compared to 2016 and the effective tax rate was 32% and 31% for 2017 and 2016, respectively. The effective tax rate increased primarily due to lower production tax credits associated with PacifiCorp's wind-powered generating facilities as a result of the expiration of the 10-year production tax credit periods for certain wind-powered generating facilities, of which 243 MWs and 100 MWs of net owned capacity expired in 2017 and 2016, respectively.
Liquidity and Capital Resources
As of December 31, 2018,2021, PacifiCorp's total net liquidity was as follows (in millions):
|
| | | | |
Cash and cash equivalents | | $ | 77 |
|
| | |
Credit facilities(1) | | 1,200 |
|
Less: | | |
Short-term debt | | (30 | ) |
Tax-exempt bond support | | (89 | ) |
Net credit facilities | | 1,081 |
|
| | |
Total net liquidity | | $ | 1,158 |
|
| | |
Credit facilities: | | |
Maturity dates | | 2021 |
|
| | | | | | | | |
(1)Cash and cash equivalents | | $ | 179 | |
| | |
Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding PacifiCorp'sCredit facilities(1)
| | 1,200 | |
Less: | | |
| | |
Tax-exempt bond support | | (218) | |
Net credit facilities.facilities | | 982 | |
| | |
Total net liquidity | | $ | 1,161 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding PacifiCorp's credit facilities.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 20182021 and 20172020 were $1.8 billion and $1.6 billion, respectively. The increase is primarily due to current year lower paymentshigher cash received for income taxes a prior year pension contribution and higher current year receiptscollections from wholesaleretail customers, partially offset by lower current year receipts from retail customershigher wholesale purchases and higher payments for purchased power.timing of operating payables.
Net cash flows from operating activities for the years ended December 31, 20172020 and 20162019 were $1.6 billion and $1.6$1.5 billion, respectively. Positive variances from the 2016 paymentThe increase is primarily due to lower purchased power prices, lower cash paid for USA Power litigation, higher receiptsincome taxes and lower operating expense payments due to timing, partially offset by lower collections from wholesale and retail customers and lowerhigher fuel expense payments were fully offset by current year higher cash payments for purchased power, income taxes and pension contributions.due to timing.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 20182021 and 20172020 were $(1,252) million$(1.5) billion and $(757) million,$(2.5) billion, respectively. The changedecrease in net cash outflows from investing activities is mainly reflects an increasedue to a decrease in capital expenditures of $488 million.$1.0 billion.
Net cash flows from investing activities for the years ended December 31, 20172020 and 20162019 were $(757) million$(2.5) billion and $(895) million,$(2.2) billion, respectively. The changeincrease in net cash outflows from investing activities is mainly reflects a decreasedue to an increase in capital expenditures of $134 million.$365 million, partially offset by proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015.
Financing Activities
Short-term Debt and Credit Facilities
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31, 2018,2021, PacifiCorp had $30no short-term debt outstanding. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 2.85%. As of December 31, 2017, PacifiCorp had $80 million of short-term debt outstanding at a weighted average interest rate of 1.83%0.16%. For further discussion, refer to Note 67 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Long-term Debt
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
In July 2018,2021, PacifiCorp issued $600 million$1 billion of its 4.125%2.90% First Mortgage Bonds due January 2049.June 2052. PacifiCorp used the net proceeds to finance a portion of the net proceeds to repay all of PacifiCorp's $500 million 5.65% First Mortgage Bonds due July 2018 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.
PacifiCorp currently has regulatory authoritydisbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the OPUCEnergy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the IPUC to issue an additional $2 billionconstruction and acquisition of long-term debt. PacifiCorp must make a notice filingnew wind-powered generating facilities, which were previously financed with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue up to $2 billion additional first mortgage bonds through October 2021.PacifiCorp's general funds.
PacifiCorp made repayments on long-term debt excluding repayments for lease obligations, totaling $586$870 million and $52$38 million during the years ended December 31, 20182021 and 2017,2020, respectively.
As of December 31, 2018, PacifiCorp had $170 million of letters of credit providing credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $168 million plus interest. These letters of credit were fully available as of December 31, 2018 and expire in March 2019.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2018,2021, PacifiCorp estimated it would be able to issue up to $10.3$11.8 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances are subject to market conditions and amounts may beare further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
Credit Facilities
In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.
In 2020, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations decreased by $38 million due to maturities.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.
Preferred Stock
As of December 31, 20182021 and 2017,2020, PacifiCorp had non-redeemable preferred stock outstanding with an aggregate stated value of $2 million.
Common Shareholder's Equity
In 20182021 and 2017,2020, PacifiCorp declared and paid dividends of $450$150 million and $600$— million, respectively, to PPW Holdings LLC.
Capitalization
PacifiCorp manages its capitalization and liquidity position to maintain a prudent capital structure with an objective of retaining strong investment grade credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, customers and creditors and provide a competitive cost of capital and predictable capital market access.
Under existing or prospective authoritative accounting guidance, such as guidance pertaining to consolidations and leases, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as capital lease obligations or debt on PacifiCorp's financial statements. While PacifiCorp has successfully amended covenants in financing arrangements that may be impacted, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers under financing agreements and from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its indirect parent company, BHE, or take other actions.
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Wind generation | $ | 933 | | | $ | 1,277 | | | $ | 131 | | | $ | 210 | | | $ | 473 | | | $ | 440 | |
Electric distribution | 413 | | | 613 | | | 618 | | | 610 | | | 586 | | | 515 | |
Electric transmission | 612 | | | 405 | | | 315 | | | 927 | | | 1,617 | | | 836 | |
Other | 217 | | | 245 | | | 449 | | | 254 | | | 641 | | | 710 | |
Total | $ | 2,175 | | | $ | 2,540 | | | $ | 1,513 | | | $ | 2,001 | | | $ | 3,317 | | | $ | 2,501 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| | | | | | | | | | | |
Transmission system investment | $ | 94 |
| | $ | 115 |
| | $ | 75 |
| | $ | 484 |
| | $ | 182 |
| | $ | 33 |
|
Wind investment | 110 |
| | 11 |
| | 341 |
| | 987 |
| | 1,150 |
| | 10 |
|
Operating and other | 699 |
| | 643 |
| | 841 |
| | 822 |
| | 929 |
| | 834 |
|
Total | $ | 903 |
| | $ | 769 |
| | $ | 1,257 |
| | $ | 2,293 |
| | $ | 2,261 |
| | $ | 877 |
|
PacifiCorp's 2019 and 2021 IRPs identified a roadmap for a significant increase in renewable and carbon free generation resources, coal to natural gas conversion of certain coal-fueled units, energy storage and associated transmission. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
Transmission system investment primarily reflects initial costs•Wind generation includes both growth projects and operating expenditures. Growth projects include:
◦Construction of wind-powered generating facilities at PacifiCorp totaled $107 million for 2021, $1,148 million for 2020 and $338 million for 2019. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in-service in 2021. Planned spending for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segmentconstruction of additional wind-powered generating facilities totals $131 million in 2022, $405 million in 2023 and $373 million in 2024.
◦Repowering of existing wind-powered generating facilities at PacifiCorp totaled $9 million in 2021, $125 million in 2020 and $585 million in 2019. All existing wind-powered generating facilities at PacifiCorp have been repowered as of December 31, 2021.
◦The 2021 IRP also included PacifiCorp's Energy Gateway Transmission expansion programplanned acquisition and repowering of two wind-powered generating facilities. The repowered facilities are expected to be placed in-service in 2020. Planned2023 and 2024. PacifiCorp spent $11 million in 2021 and planned spending for the Aeolus-Bridger/Anticline lineacquiring and repowering generating facilities totals $436$60 million in 2019, $1122022, $36 million in 2023 and $34 million in 2024.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $176 million in 2021, $187 million in 2020 and $1$4 million in 2021.2019, and planned spending totals $153 million in 2022, $133 million in 2023 and $127 million in 2024. Remaining investments relate to expenditures for new connections and distribution operations.
Wind•Electric transmission includes both growth projects and operating expenditures. Transmission investment in 2021 through 2024 primarily reflects planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. PacifiCorp is advancing permitting and regulatory approvals related to the projects. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $565 million in 2022, $1,143 million in 2023, and $437 million in 2024.
•Other includes the following:
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◦ | The new wind-powered generating facilities are expected to be placed in-service in 2020. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal production tax credits available for 10 years once the equipment is placed in-service. Planned spending for the wind-powered generating facilities totals $420 million in 2019, $991 million in 2020 and $9 million in 2021. |
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◦ | Repowering existing wind-powered generating facilities at PacifiCorp totaled $332 million in 2018 and $6 million in 2017. The repowering projects are expected to be placed in-service at various dates in 2019 and 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity production tax credits available for 10 years following each facility's return to service. Planned spending for certain existing wind-powered generating facilities totals $567 million in 2019, $159 million in 2020 and $1 million in 2021. |
both growth projects and operating expenditures. Expenditures for information technology totaled $108 million in 2021, $75 million in 2020 and $62 million for 2019. Planned information technology spending totals $167 million in 2022, $163 million in 2023 and $136 million in 2024. Remaining investments relate to operating projects that consist of advanced meter infrastructure costs, routine expenditures for generation transmission, distribution and other infrastructure needed to serve existing and expected demand.
Contractual Obligations
Off-Balance Sheet Arrangements
PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees or similar arrangements. PacifiCorp currently has indemnification obligations in connection with the sale or transfer of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with authoritative accounting guidance. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. Refer to Notes 11 and 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these obligations and arrangements.
Material Cash Requirements
PacifiCorp has contractual cash obligationsrequirements that may affect its consolidated financial condition. The following table summarizes PacifiCorp's material contractualcondition that arise primarily from long-term debt (refer to Note 8), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), cost of removal and AROs (refer to Notes 6 and 11), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
PacifiCorp has cash obligations asrequirements relating to interest payments of December 31, 2018 (in millions):$6.5 billion on long-term debt, including $400 million due in 2022.
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| | | | | | | | | | | | | | | | | | | |
| Payments Due By Periods |
| 2019 | | 2020-2021 | | 2022-2023 | | 2024 and Thereafter | | Total |
| | | | | | | | | |
Long-term debt, including interest: | | | | | | | | | |
Fixed-rate obligations | $ | 692 |
| | $ | 1,077 |
| | $ | 1,645 |
| | $ | 8,529 |
| | $ | 11,943 |
|
Variable-rate obligations(1) | 4 |
| | 47 |
| | 8 |
| | 222 |
| | 281 |
|
Short-term debt, including interest | 30 |
| | — |
| | — |
| | — |
| | 30 |
|
Capital leases, including interest | 4 |
| | 10 |
| | 5 |
| | 16 |
| | 35 |
|
Operating leases and easements | 7 |
| | 13 |
| | 11 |
| | 90 |
| | 121 |
|
Asset retirement obligations | 21 |
| | 18 |
| | 23 |
| | 388 |
| | 450 |
|
Power purchase agreements - commercially operable(2): | | | | | | | | | |
Electricity commodity contracts | 274 |
| | 269 |
| | 222 |
| | 841 |
| | 1,606 |
|
Electricity capacity contracts | 35 |
| | 65 |
| | 61 |
| | 633 |
| | 794 |
|
Electricity mixed contracts | 8 |
| | 15 |
| | 14 |
| | 48 |
| | 85 |
|
Power purchase agreements - non-commercially operable(2) | 13 |
| | 69 |
| | 98 |
| | 797 |
| | 977 |
|
Transmission | 108 |
| | 175 |
| | 132 |
| | 427 |
| | 842 |
|
Fuel purchase agreements(2): | | | | | | | | | |
Natural gas supply and transportation | 57 |
| | 54 |
| | 53 |
| | 207 |
| | 371 |
|
Coal supply and transportation | 675 |
| | 1,115 |
| | 541 |
| | 769 |
| | 3,100 |
|
Other purchase obligations | 940 |
| | 612 |
| | 24 |
| | 81 |
| | 1,657 |
|
Other long-term liabilities(3) | 17 |
| | 19 |
| | 15 |
| | 60 |
| | 111 |
|
Total contractual cash obligations | $ | 2,885 |
| | $ | 3,558 |
| | $ | 2,852 |
| | $ | 13,108 |
| | $ | 22,403 |
|
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(1) | Consists of principal and interest for tax-exempt bond obligations with interest rates scheduled to reset periodically prior to maturity. Future variable interest rates are assumed to equal December 31, 2018 rates. Refer to "Interest Rate Risk" in Item 7A of this Form 10-K for additional discussion related to variable-rate liabilities. |
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(2) | Commodity contracts are agreements for the delivery of energy. Capacity contracts are agreements that provide rights to energy output, generally of a specified generating facility. Forecasted or other applicable estimated prices were used to determine total dollar value of the commitments. PacifiCorp has several contracts for purchases of electricity from facilities that have not yet achieved commercial operation. To the extent any of these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty. |
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(3) | Includes environmental and hydroelectric relicensing commitments recorded in the Consolidated Balance Sheets that are contractually or legally binding. Excludes regulatory liabilities and employee benefit plan obligations that are not legally or contractually fixed as to timing and amount. Deferred income taxes are excluded since cash payments are based primarily on taxable income for each year. Uncertain tax positions are also excluded because the amounts and timing of cash payments are not certain. |
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussioninformation regarding PacifiCorp's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state local and foreignlocal laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state local and internationallocal agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2018,2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Servicesfrom the recognized credit rating agencies were investment grade.
PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2018,2021, PacifiCorp would have been required to post $289$218 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 1112 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.
Inflation
Historically, overall inflation and changing prices in the economies where PacifiCorp operates have not had a significant impact on PacifiCorp's consolidated financial results. PacifiCorp operates under a cost-of-service based rate structure administered by various state commissions and the FERC. Under this rate structure, PacifiCorp is allowed to include prudent costs in its rates, including the impact of inflation. PacifiCorp attemptsseeks to minimize the potential impact of inflation on its operations through the use of energy and other cost adjustment clauses and billtariff riders, by employing prudent risk management and hedging strategies and entering into contracts with fixed pricing where possible by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Off-Balance Sheet Arrangements
PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees or similar arrangements. PacifiCorp currently has indemnification obligations in connection with the sale of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with authoritative accounting guidance. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. Refer to Notes 10 and 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these obligations and arrangements.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by PacifiCorp's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with PacifiCorp's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be written offrecognized in net income, returned to net incomecustomers or re-established as accumulated other comprehensive income (loss).AOCI. Total regulatory assets were $1.112$1.4 billion and total regulatory liabilities were $3.055$2.8 billion as of December 31, 2018.2021. Refer to Note 56 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's regulatory assets and liabilities.
Derivatives
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage its commodity price and, at times, interest rate risk. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices and interest rates. As of December 31, 2018, PacifiCorp had no derivative contracts outstanding related to interest rate risk. Refer to Notes 11 and 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's derivative contracts.
Measurement Principles
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by accounting principles generally accepted in the United States of America. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. As of December 31, 2018, PacifiCorp had a net derivative liability of $97 million related to contracts valued using either quoted prices or forward price curves based upon observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are critical because any changes in assumptions could have a significant impact on the estimated fair value of the contracts. As of December 31, 2018, PacifiCorp had a net derivative asset of $- million related to contracts where PacifiCorp uses internal models with significant unobservable inputs.
Classification and Recognition Methodology
PacifiCorp's derivative contracts are probable of inclusion in rates and changes in the estimated fair value of derivative contracts are generally recorded as regulatory assets. Accordingly, amounts are generally not recognized in earnings until the contracts are settled and the forecasted transaction has occurred. As of December 31, 2018, PacifiCorp had $96 million recorded as a regulatory asset related to derivative contracts on the Consolidated Balance Sheets.
Pension and Other Postretirement Benefits
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. In addition, PacifiCorp contributes to a joint trustee pension plan for benefits offered to certain bargaining units.as described in Note 10. PacifiCorp recognizes the funded status of itsthese defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2018,2021, PacifiCorp recognized a net liabilityasset totaling $164$46 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2018,2021, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets and accumulated other comprehensive loss totaled $448$260 million and $17$23 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rate and expected long-term rate of return on plan assets. These key assumptions are reviewed annually and modified as appropriate. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 910 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about PacifiCorp's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2018.2021.
PacifiCorp chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that correspondswith cash flows aligning to the expected benefit period.timing and amount of plan liabilities. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, PacifiCorp evaluates the investment allocation between return-seeking investment and fixed income securities based on the funded status of the plan and utilizes the asset allocation and return assumptions for each asset class based on forward-looking views of the financial markets and historical performance. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. PacifiCorp regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plan |
| +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | |
Effect on December 31, 2021 Benefit Obligations: | | | | | | | |
Discount rate | $ | (50) | | | $ | 55 | | | $ | (13) | | | $ | 15 | |
| | | | | | | |
Effect on 2021 Periodic Cost: | | | | | | | |
Discount rate | $ | — | | | $ | — | | | $ | 1 | | | $ | (1) | |
Expected rate of return on plan assets | (5) | | | 5 | | | (2) | | | 2 | |
|
| | | | | | | | | | | | | | | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plan |
| +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | |
Effect on December 31, 2018 Benefit Obligations: | | | | | | | |
Discount rate | $ | (55 | ) | | $ | 60 |
| | $ | (12 | ) | | $ | 13 |
|
| | | | | | | |
Effect on 2018 Periodic Cost: | | | | | | | |
Discount rate | $ | 1 |
| | $ | (1 | ) | | $ | 1 |
| | $ | (1 | ) |
Expected rate of return on plan assets | (5 | ) | | 5 |
| | (2 | ) | | 2 |
|
A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and PacifiCorp's funding policy for each plan.
Income Taxes
In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on PacifiCorp's consolidated financial results. Refer to Note 89 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's income taxes.
It is probable that PacifiCorp is required towill pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences excess deferred income taxes resulting from 2017 Tax Reform and other various differences on to its customers.their customers in certain state jurisdictions. As of December 31, 2018,2021, these amounts were recognized as a net regulatory liability of $1.8$1.3 billion and will be included in regulated rates when the temporary differences reverse, or as otherwise specifically ordered by regulatory commissions.reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $229$264 million as of December 31, 2018.2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
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Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
PacifiCorp's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. PacifiCorp's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which PacifiCorp transacts. The following discussion addresses the significant market risks associated with PacifiCorp's business activities. PacifiCorp has established guidelines for credit risk management. Refer to Notes 2 and 1112 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's contracts accounted for as derivatives.
Risk Management
PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp's exposure to market and credit risk, the risk management committee recommends, and executive management establishes, policies, limits and approved products, which are reviewed frequently to respond to changing market conditions.
Risk is an inherent part of PacifiCorp's business and activities. PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigatereport on each of the various types of risk involved in PacifiCorp's business. The risk management policy governs energy transactions and is designed for hedging PacifiCorp's existing energy and asset exposures, and to a limited extent, the policy permits arbitrage and trading activities to take advantage of market inefficiencies. The policy also governs the types of transactions authorized for use and establishes guidelines for credit risk management and management information systems required to effectively monitor such transactions. PacifiCorp's risk management policy provides for the use of only those contracts that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions.
Commodity Price Risk
PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as PacifiCorp has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. PacifiCorp does not engage in a material amount of proprietary trading activities. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. PacifiCorp's exposure to commodity price risk is generally limited by its ability to include commodity costs in rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
PacifiCorp measures, monitors and manages the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk ("VaR") approach and other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period. VaR computations for thePacifiCorp has a risk management policy that requires increasing volumes of hedge transactions over a three-year position management and hedging horizon to reduce market risk of its electricity and natural gas commodity portfolio are based on a historical simulation technique, utilizing historical price changes over a specified (holding) period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions. The quantification of market risk using VaR provides a consistent measure of risk across PacifiCorp's continually changing portfolio. VaR represents an estimate of possible changes at a given level of confidence in fair value that would be measured on its portfolio assuming hypothetical movements in forward market prices and is not necessarily indicative of actual results that may occur.
PacifiCorp's VaR computations utilize several key assumptions. The calculation includes short-term commodity contracts, the expected resource and demand obligations from PacifiCorp's long-term contracts, the expected generation levels from PacifiCorp's generation assets and the expected retail and wholesale load levels. The portfolio reflects flexibility contained in contracts and assets, which accommodate the normal variability in PacifiCorp's demand obligations and generation availability. These contracts and assets are valued to reflect the variability PacifiCorp experiences as a load-serving entity. Contracts or assets that contain flexible elements are often referred to as having embedded options or option characteristics. These options provide for energy volume changes that are sensitive to market price changes. Therefore, changes in the option values affect the energy position of the portfolio with respect to market prices, and this effect is calculated daily. When measuring portfolio exposure through VaR, these position changes that result from the option sensitivity are held constant through the historical simulation. PacifiCorp's VaR methodology is based on a 36-month forward position, 95% confidence interval and one-day holding period.
As of December 31, 2018, PacifiCorp's estimated potential one-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 36 months was $10 million, as measured by the VaR computations described above. The minimum, average and maximum daily VaR (one-day holding periods) were as follows for the year ended December 31 (in millions):
|
| | | |
| 2018 |
Minimum VaR (measured) | $ | 7 |
|
Average VaR (calculated) | 9 |
|
Maximum VaR (measured) | 13 |
|
PacifiCorp maintained compliance with its VaRrisk management policy and limit procedures during the year ended December 31, 2018. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed estimated VaR levels.2021.
Fair Value of Derivatives
The table that follows summarizes PacifiCorp's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $59$5 million and $74$24 million as of December 31, 20182021 and 2017,2020, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | 53 | | | $ | 104 | | | $ | 2 | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | (17) | | | $ | 5 | | | $ | (39) | |
|
| | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2018: | | | | | |
Total commodity derivative contracts | $ | (97 | ) | | $ | (92 | ) | | $ | (102 | ) |
| | | | | |
As of December 31, 2017 | | | | | |
Total commodity derivative contracts | $ | (104 | ) | | $ | (102 | ) | | $ | (106 | ) |
PacifiCorp's commodity derivative contracts are generally recoverable from customers in rates; therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose PacifiCorp to earnings volatility. As of December 31, 20182021 and 2017,2020, a regulatory liability of $53 million and a regulatory asset of $96 million and $101$17 million, respectively, was recorded related to the net derivative asset of $53 million and a net derivative liability of $97 million and $104$17 million, respectively. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, natural gas or fuel are higher or the level of wholesale electricity sales are lower than what is included in rates, including the impacts of adjustment mechanisms.
Interest Rate Risk
PacifiCorp is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, PacifiCorp's fixed-rate long-term debt does not expose PacifiCorp to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity. PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. The nature and amount of PacifiCorp's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 6, 7, 8 and 1213 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of PacifiCorp's short- and long-term debt.
As of December 31, 20182021 and 2017,2020, PacifiCorp had short- and long-term variable-rate obligations totaling $285$218 million and $442$310 million, respectively that expose PacifiCorp to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to PacifiCorp's variable-rate debt as of December 31, 20182021 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on PacifiCorp's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 20182021 and 2017.2020.
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2018,2021, PacifiCorp's aggregate credit exposure fromwith wholesale activities totaled $719 million, based on settlementenergy supply and mark-to-market exposures, netmarketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of collateral, compared to $127 million as of December 31, 2017. As of December 31, 2018, $552 million of PacifiCorp's total credit exposure relates tothese non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, entered into to meet customer requests for renewable energy. The credit exposure for these long-duration solar power purchase agreements was estimated using forward price curves derived from market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. The power purchase agreementssome of which are from facilities that have not yet achieved commercial operation. To the extent any of these facilities do not achieve commercial operation by contractually agreed upon dates,and for which PacifiCorp has no obligation toshould the counterparty.facilities not achieve commercial operation.
Item 8.Financial Statements and Supplementary Data
| |
Item 8. | Financial Statements and Supplementary Data |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PacifiCorp and subsidiaries ("PacifiCorp") as of December 31, 20182021 and 2017,2020, the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2018,2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of PacifiCorp as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of PacifiCorp’sPacifiCorp's management. Our responsibility is to express an opinion on PacifiCorp’sPacifiCorp's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. PacifiCorp is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of PacifiCorp’sPacifiCorp's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
PacifiCorp is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to rates in the respective service territories where PacifiCorp operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense; and income tax expense (benefit).
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow PacifiCorp an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While PacifiCorp has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit PacifiCorp's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated PacifiCorp's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected PacifiCorp's filings with the Commissions and the filings with the Commissions by intervenors that may impact PacifiCorp's future rates, for any evidence that might contradict management's assertions.
We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
California and Oregon 2020 Wildfires – Contingencies – See Note 14 to the financial statements
Critical Audit Matter Description
PacifiCorp has loss contingencies related to the California and Oregon 2020 wildfires (the "2020 wildfires"). PacifiCorp has recorded estimated liabilities, net of expected insurance recoveries, of $136 million as of December 31, 2021, which represents its best estimate of probable losses, net of expected insurance recoveries, as a result of the 2020 wildfires.
We identified wildfire-related contingencies and the related disclosure as a critical audit matter because of the significant judgments made by management to estimate the losses. This required the application of a high degree of judgment and extensive effort when performing audit procedures to evaluate the reasonableness of management's estimate of the losses and disclosure related to wildfire-related loss contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding its estimate of losses for wildfire-related contingencies and the related disclosure included the following, among others:
•We evaluated management's judgments related to whether a loss was probable and reasonably estimable, reasonably possible, or remote for each individual wildfire by inquiring of management and PacifiCorp's external and internal legal counsel regarding the amounts of probable and reasonably estimable, reasonably possible, and remote losses, including the potential impact of information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire, and external information for any evidence that might contradict management's assertions.
•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management and its external and internal legal counsel.
•We tested the significant assumptions used in determining the estimate, including, but not limited to, information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire.
•We read legal letters from PacifiCorp's external and internal legal counsel regarding information regarding ongoing litigation related to the 2020 wildfires and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated whether PacifiCorp's disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ Deloitte & Touche LLP
Portland, Oregon
February 22, 201925, 2022
We have served as PacifiCorp's auditor since 2006.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 179 | | | $ | 13 | |
Trade receivables, net | 725 | | | 703 | |
Other receivables, net | 52 | | | 48 | |
Inventories | 474 | | | 482 | |
Regulatory assets | 65 | | | 116 | |
Prepaid expenses | 79 | | | 79 | |
Other current assets | 147 | | | 82 | |
Total current assets | 1,721 | | | 1,523 | |
| | | |
Property, plant and equipment, net | 22,914 | | | 22,430 | |
Regulatory assets | 1,287 | | | 1,279 | |
Other assets | 534 | | | 470 | |
| | | |
Total assets | $ | 26,456 | | | $ | 25,702 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 77 |
| | $ | 14 |
|
Trade receivables, net | 640 |
| | 631 |
|
Other receivables, net | 92 |
| | 53 |
|
Inventories | 417 |
| | 433 |
|
Prepaid expenses | 47 |
| | 73 |
|
Other current assets | 86 |
| | 111 |
|
Total current assets | 1,359 |
| | 1,315 |
|
| | | |
Property, plant and equipment, net | 19,591 |
| | 19,203 |
|
Regulatory assets | 1,076 |
| | 1,030 |
|
Other assets | 287 |
| | 372 |
|
| | | |
Total assets | $ | 22,313 |
| | $ | 21,920 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | |
Current liabilities: | | | |
Accounts payable | $ | 680 | | | $ | 772 | |
Accrued interest | 121 | | | 127 | |
Accrued property, income and other taxes | 78 | | | 80 | |
Accrued employee expenses | 89 | | | 84 | |
Short-term debt | — | | | 93 | |
Current portion of long-term debt | 155 | | | 420 | |
Regulatory liabilities | 118 | | | 115 | |
Other current liabilities | 219 | | | 174 | |
Total current liabilities | 1,460 | | | 1,865 | |
| | | |
Long-term debt | 8,575 | | | 8,192 | |
Regulatory liabilities | 2,650 | | | 2,727 | |
Deferred income taxes | 2,847 | | | 2,627 | |
Other long-term liabilities | 1,011 | | | 1,118 | |
Total liabilities | 16,543 | | | 16,529 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholders' equity: | | | |
Preferred stock | 2 | | | 2 | |
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 4,479 | | | 4,479 | |
Retained earnings | 5,449 | | | 4,711 | |
Accumulated other comprehensive loss, net | (17) | | | (19) | |
Total shareholders' equity | 9,913 | | | 9,173 | |
| | | |
Total liabilities and shareholders' equity | $ | 26,456 | | | $ | 25,702 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | |
Current liabilities: | | | |
Accounts payable | $ | 597 |
| | $ | 453 |
|
Accrued interest | 114 |
| | 115 |
|
Accrued property, income and other taxes | 75 |
| | 66 |
|
Accrued employee expenses | 79 |
| | 70 |
|
Short-term debt | 30 |
| | 80 |
|
Current portion of long-term debt and capital lease obligations | 352 |
| | 588 |
|
Regulatory liabilities | 77 |
| | 75 |
|
Other current liabilities | 191 |
| | 170 |
|
Total current liabilities | 1,515 |
| | 1,617 |
|
| | | |
Long-term debt and capital lease obligations | 6,684 |
| | 6,437 |
|
Regulatory liabilities | 2,978 |
| | 2,996 |
|
Deferred income taxes | 2,543 |
| | 2,582 |
|
Other long-term liabilities | 748 |
| | 733 |
|
Total liabilities | 14,468 |
| | 14,365 |
|
| | | |
Commitments and contingencies (Note 13) |
| |
|
| | | |
Shareholders' equity: | | | |
Preferred stock | 2 |
| | 2 |
|
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | — |
| | — |
|
Additional paid-in capital | 4,479 |
| | 4,479 |
|
Retained earnings | 3,377 |
| | 3,089 |
|
Accumulated other comprehensive loss, net | (13 | ) | | (15 | ) |
Total shareholders' equity | 7,845 |
| | 7,555 |
|
| | | |
Total liabilities and shareholders' equity | $ | 22,313 |
| | $ | 21,920 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 1,831 | | | 1,790 | | | 1,795 | |
Operations and maintenance | 1,031 | | | 1,209 | | | 1,048 | |
Depreciation and amortization | 1,088 | | | 1,209 | | | 954 | |
Property and other taxes | 213 | | | 209 | | | 199 | |
Total operating expenses | 4,163 | | | 4,417 | | | 3,996 | |
| | | | | |
Operating income | 1,133 | | | 924 | | | 1,072 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (430) | | | (426) | | | (401) | |
Allowance for borrowed funds | 24 | | | 48 | | | 36 | |
Allowance for equity funds | 50 | | | 98 | | | 72 | |
Interest and dividend income | 24 | | | 10 | | | 21 | |
Other, net | 8 | | | 10 | | | 32 | |
Total other expense | (324) | | | (260) | | | (240) | |
| | | | | |
Income before income tax (benefit) expense | 809 | | | 664 | | | 832 | |
Income tax (benefit) expense | (79) | | | (75) | | | 61 | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Operating revenue | $ | 5,026 |
| | $ | 5,237 |
| | $ | 5,201 |
|
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 1,757 |
| | 1,770 |
| | 1,751 |
|
Operations and maintenance | 1,038 |
| | 1,034 |
| | 1,062 |
|
Depreciation and amortization | 979 |
| | 796 |
| | 770 |
|
Taxes, other than income taxes | 201 |
| | 197 |
| | 190 |
|
Total operating expenses | 3,975 |
| | 3,797 |
| | 3,773 |
|
| | | | | |
Operating income | 1,051 |
| | 1,440 |
| | 1,428 |
|
| | | | | |
Other income (expense): | | | | | |
Interest expense | (384 | ) | | (381 | ) | | (380 | ) |
Allowance for borrowed funds | 18 |
| | 11 |
| | 15 |
|
Allowance for equity funds | 35 |
| | 20 |
| | 27 |
|
Other, net | 23 |
| | 38 |
| | 13 |
|
Total other income (expense) | (308 | ) | | (312 | ) | | (325 | ) |
| | | | | |
Income before income tax expense | 743 |
| | 1,128 |
| | 1,103 |
|
Income tax expense | 5 |
| | 360 |
| | 340 |
|
Net income | $ | 738 |
| | $ | 768 |
| | $ | 763 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
| | | | | |
Other comprehensive income (loss), net of tax — | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $1, $(1) and $(1) | 2 | | | (3) | | | (3) | |
| | | | | |
Comprehensive income | $ | 890 | | | $ | 736 | | | $ | 768 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 738 |
| | $ | 768 |
| | $ | 763 |
|
| | | | | |
Other comprehensive income (loss), net of tax — | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $1, $3 and $- | 2 |
| | (3 | ) | | (1 | ) |
| | | | | |
Comprehensive income | $ | 740 |
| | $ | 765 |
| | $ | 762 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated | | |
| | | | | Additional | | | | Other | | Total |
| Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2018 | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 3,377 | | | $ | (13) | | | $ | 7,845 | |
Net income | — | | | — | | | — | | | 771 | | | — | | | 771 | |
Other comprehensive loss | — | | | — | | | — | | | (1) | | | (3) | | | (4) | |
Common stock dividends declared | — | | | — | | | — | | | (175) | | | — | | | (175) | |
Balance, December 31, 2019 | 2 | | | — | | | 4,479 | | | 3,972 | | | (16) | | | 8,437 | |
Net income | — | | | — | | | — | | | 739 | | | — | | | 739 | |
Other comprehensive loss | — | | | — | | | — | | | — | | | (3) | | | (3) | |
| | | | | | | | | | | |
Balance, December 31, 2020 | 2 | | | — | | | 4,479 | | | 4,711 | | | (19) | | | 9,173 | |
Net income | — | | | — | | | — | | | 888 | | | — | | | 888 | |
Other comprehensive income | — | | | — | | | — | | | — | | | 2 | | | 2 | |
Common stock dividends declared | — | | | — | | | — | | | (150) | | | — | | | (150) | |
Balance, December 31, 2021 | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,449 | | | $ | (17) | | | $ | 9,913 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated | | |
| | | | | Additional | | | | Other | | Total |
| Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2015 | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 3,033 |
| | $ | (11 | ) | | $ | 7,503 |
|
Net income | — |
| | — |
| | — |
| | 763 |
| | — |
| | 763 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
Common stock dividends declared | — |
| | — |
| | — |
| | (875 | ) | | — |
| | (875 | ) |
Balance, December 31, 2016 | 2 |
| | — |
| | 4,479 |
| | 2,921 |
| | (12 | ) | | 7,390 |
|
Net income | — |
| | — |
| | — |
| | 768 |
| | — |
| | 768 |
|
Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | (3 | ) | | (3 | ) |
Common stock dividends declared | — |
| | — |
| | — |
| | (600 | ) | | — |
| | (600 | ) |
Balance, December 31, 2017 | 2 |
| | — |
| | 4,479 |
| | 3,089 |
| | (15 | ) | | 7,555 |
|
Net income | — |
| | — |
| | — |
| | 738 |
| | — |
| | 738 |
|
Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Common stock dividends declared | — |
| | — |
| | — |
| | (450 | ) | | — |
| | (450 | ) |
Balance, December 31, 2018 | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 3,377 |
| | $ | (13 | ) | | $ | 7,845 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
Adjustments to reconcile net income to net cash flows from operating | | | | | |
activities: | | | | | |
Depreciation and amortization | 1,088 | | | 1,209 | | | 954 | |
Allowance for equity funds | (50) | | | (98) | | | (72) | |
Changes in regulatory assets and liabilities | (189) | | | (229) | | | (55) | |
Deferred income taxes and amortization of investment tax credits | 64 | | | (124) | | | (131) | |
Other, net | (5) | | | 1 | | | 20 | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables, other receivables and other assets | 15 | | | (154) | | | 26 | |
Inventories | 8 | | | (88) | | | 23 | |
Prepaid expenses | 2 | | | (15) | | | (12) | |
Derivative collateral, net | 19 | | | 23 | | | 12 | |
Accrued property, income and other taxes, net | (37) | | | (53) | | | 22 | |
Accounts payable and other liabilities | 1 | | | 372 | | | (11) | |
Net cash flows from operating activities | 1,804 | | | 1,583 | | | 1,547 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (1,513) | | | (2,540) | | | (2,175) | |
Other, net | 12 | | | 30 | | | 11 | |
Net cash flows from investing activities | (1,501) | | | (2,510) | | | (2,164) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 984 | | | 987 | | | 989 | |
Repayments of long-term debt | (870) | | | (38) | | | (350) | |
(Repayments of) net proceeds from short-term debt | (93) | | | (37) | | | 100 | |
| | | | | |
Dividends paid | (150) | | | — | | | (175) | |
Other, net | (7) | | | (2) | | | (3) | |
Net cash flows from financing activities | (136) | | | 910 | | | 561 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 167 | | | (17) | | | (56) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 19 | | | 36 | | | 92 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 186 | | | $ | 19 | | | $ | 36 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Cash flows from operating activities: | | | | | |
Net income | $ | 738 |
| | $ | 768 |
| | $ | 763 |
|
Adjustments to reconcile net income to net cash flows from operating | | | | | |
activities: |
| |
| |
|
Depreciation and amortization | 979 |
| | 796 |
| | 770 |
|
Allowance for equity funds | (35 | ) | | (20 | ) | | (27 | ) |
Changes in regulatory assets and liabilities | 87 |
| | 18 |
| | 122 |
|
Deferred income taxes and amortization of investment tax credits | (199 | ) | | 70 |
| | 139 |
|
Other, net | 5 |
| | 9 |
| | 4 |
|
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | 31 |
| | 75 |
| | 6 |
|
Inventories | 16 |
| | 10 |
| | (21 | ) |
Derivative collateral, net | 15 |
| | (6 | ) | | 6 |
|
Prepaid expenses | 31 |
| | (8 | ) | | (5 | ) |
Accrued property, income and other taxes, net | 60 |
| | (48 | ) | | — |
|
Accounts payable and other liabilities | 83 |
| | (62 | ) | | (163 | ) |
Net cash flows from operating activities | 1,811 |
| | 1,602 |
| | 1,594 |
|
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (1,257 | ) | | (769 | ) | | (903 | ) |
Other, net | 5 |
| | 12 |
| | 8 |
|
Net cash flows from investing activities | (1,252 | ) | | (757 | ) | | (895 | ) |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 593 |
| | — |
| | — |
|
Repayments of long-term debt and capital lease obligations | (588 | ) | | (58 | ) | | (68 | ) |
Net (repayments) proceeds from short-term debt | (50 | ) | | (190 | ) | | 250 |
|
Dividends paid | (450 | ) | | (600 | ) | | (875 | ) |
Other, net | (1 | ) | | (1 | ) | | (1 | ) |
Net cash flows from financing activities | (496 | ) | | (849 | ) | | (694 | ) |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 63 |
| | (4 | ) | | 5 |
|
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 29 |
| | 33 |
| | 28 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 92 |
| | $ | 29 |
| | $ | 33 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)Organization and Operations
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2)Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies.loss contingencies, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") described in Note 14. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be written offrecognized in net income, returned to net incomecustomers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing escrow accounts for disputes, vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Investments
Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December 31, 20182021 and 2017,2020, PacifiCorp had no0 unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings.
Equity Method Investments
PacifiCorp utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, PacifiCorp records the investment at cost and subsequently increases or decreases the carrying value of the investment by PacifiCorp's proportionate share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. PacifiCorp records dividends or other equity distributions as reductions in the carrying value of the investment.
Allowance for Doubtful AccountsCredit Losses
Accounts receivableTrade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination, and are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts.credit losses. The allowance for doubtful accountscredit losses is based on PacifiCorp's assessment of the collectability of amounts owed to PacifiCorp by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the allowance for doubtful accounts,credit losses, which is included in accounts receivable,trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 17 | | | $ | 8 | | | $ | 8 | |
Charged to operating costs and expenses, net | 13 | | | 18 | | | 13 | |
Write-offs, net | (12) | | | (9) | | | (13) | |
Ending balance | $ | 18 | | | $ | 17 | | | $ | 8 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Beginning balance | $ | 10 |
| | $ | 7 |
| | $ | 7 |
|
Charged to operating costs and expenses, net | 12 |
| | 15 |
| | 12 |
|
Write-offs, net | (14 | ) | | (12 | ) | | (12 | ) |
Ending balance | $ | 8 |
| | $ | 10 |
| | $ | 7 |
|
Derivatives
PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or energy costs on the Consolidated Statements of Operations.
For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates are recorded as regulatory liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials, supplies and fuel stocks and are stated at the lower of average cost or net realizable value.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction ("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when PacifiCorp retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which representrepresents the estimated costs of debt and equity funds necessary to finance the construction of property, plant and equipment, is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
PacifiCorp evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. TheAs substantially all property, plant and equipment supports PacifiCorp's regulated businesses the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
PacifiCorp's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Revenue Recognition
PacifiCorp uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging."
Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. As of December 31, 20182021 and December 31, 2017,2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $229$264 million and $255$254 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Berkshire Hathaway includes PacifiCorp in its consolidated United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimatedenacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions. Investment tax credits are included in other long-term liabilities on the Consolidated Balance Sheets and were $13 million and $16 million as of December 31, 2018 and 2017, respectively.
In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on PacifiCorp's consolidated financial results. PacifiCorp's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
New Accounting Pronouncements
In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-14, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments in this guidance remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures and add disclosure requirements identified as relevant. The updated disclosure requirements make a number of changes to improve the effectiveness of disclosures in the notes to the financial statements. This guidance is effective for annual reporting periods ending after December 15, 2020, with early adoption permitted, and is required to be adopted retrospectively. PacifiCorp elected to early adopt ASU No. 2018-14 effective December 31, 2018. The adoption did not have a material impact on PacifiCorp's Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In March 2017, the FASB issued ASU No. 2017-07, which amends FASB ASC Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. PacifiCorp adopted this guidance January 1, 2018 prospectively for the capitalization of the service cost component in the Consolidated Balance Sheets and retrospectively for the presentation of the service cost component and the other components of net benefit cost in the Consolidated Statements of Operations utilizing the practical expedient to use the amounts previously disclosed in the Notes to Consolidated Financial Statements as the estimation basis for applying the retrospective presentation requirement. As a result, amounts other than the service cost for pension and other postretirement benefit plans for the year-ended December 31, 2017 and 2016 of $22 million of benefit and $2 million of cost, respectively, have been reclassified to Other, net in the Consolidated Statements of Operations.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. PacifiCorp adopted this guidance retrospectively January 1, 2018.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. PacifiCorp adopted this guidance retrospectively effective January 1, 2018 which resulted in the reclassification of certain cash distributions received from equity method investees of $27 million and $25 million previously recognized within investing cash flows to operating cash flows for the years ended December 31, 2017 and 2016.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. PacifiCorp adopted this guidance, electing all practical expedients, effective January 1, 2019, for all contracts currently in-effect. PacifiCorp is finalizing its implementation efforts relative to the new guidance and currently expects to recognize operating lease right of use assets and lease liabilities of approximately $15 million based on the contracts currently in-effect. PacifiCorp currently does not believe the adoption of the new guidance will have a material impact on its Consolidated Financial Statements and disclosures included within the Notes to the Consolidated Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue"). The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. PacifiCorp adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method. The adoption did not have a cumulative effect impact at the date of initial adoption.
(3)Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
Generation | 15 - 59 years | | $ | 13,679 | | | $ | 12,861 | |
Transmission | 60 - 90 years | | 7,894 | | | 7,632 | |
Distribution | 20 - 75 years | | 8,044 | | | 7,660 | |
Intangible plant(1) | 5 - 75 years | | 1,106 | | | 1,054 | |
Other | 5 - 60 years | | 1,539 | | | 1,510 | |
Utility plant in-service | | | 32,262 | | | 30,717 | |
Accumulated depreciation and amortization | | | (10,507) | | | (9,838) | |
Utility plant in-service, net | | | 21,755 | | | 20,879 | |
Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 9 | |
Plant, net | | | 21,773 | | | 20,888 | |
Construction work-in-progress | | | 1,141 | | | 1,542 | |
Property, plant and equipment, net | | | $ | 22,914 | | | $ | 22,430 | |
|
| | | | | | | | | |
| Depreciable Life | | 2018 | | 2017 |
Utility Plant: | | | | | |
Generation | 14 - 67 years | | $ | 12,606 |
| | $ | 12,490 |
|
Transmission | 58 - 75 years | | 6,357 |
| | 6,226 |
|
Distribution | 20 - 70 years | | 7,030 |
| | 6,792 |
|
Intangible plant(1) | 5 - 75 years | | 970 |
| | 937 |
|
Other | 5 - 60 years | | 1,483 |
| | 1,435 |
|
Utility plant in service | | | 28,446 |
| | 27,880 |
|
Accumulated depreciation and amortization | | | (10,060 | ) | | (9,366 | ) |
Utility plant in service, net | | | 18,386 |
| | 18,514 |
|
Other non-regulated, net of accumulated depreciation and amortization | 47 years | | 10 |
| | 11 |
|
Plant, net | | | 18,396 |
| | 18,525 |
|
Construction work-in-progress | | | 1,195 |
| | 678 |
|
Property, plant and equipment, net | | | $ | 19,591 |
| | $ | 19,203 |
|
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
| |
(1) | Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years. |
The average depreciation and amortization rate applied to depreciable property, plant and equipment was 3.5%, 4.1% and 3.3% for the yearyears ended December 31, 2018,2021, 2020 and 2019, respectively, including the impactimpacts of accelerated depreciation totaling $376 million and $125 million in 2020 and 2019, respectively, for Utah's share of certain thermal plant units in 2020, including Cholla Unit No. 4 in 2020 for which operations ceased in December 2020; Oregon's and 2.9%Idaho's shares of Cholla Unit No. 4 in 2020; and Oregon's share of certain retired wind equipment associated with wind repowering projects in 2020 and 2019. As discussed in Notes 6 and 9, existing regulatory liabilities primarily associated with the Utah Sustainability and Transportation Plan ("STEP") and 2017 Tax Reform benefits were utilized to accelerate depreciation of these assets.
Effective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase in depreciation expense of approximately $158 million for the yearsyear ended December 31, 20172021, as compared to the year ended December 31, 2020, based on historical property, plant and 2016, respectively.equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.
Unallocated Acquisition Adjustments
PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in property, plant and equipment purchased from the entity that first devoteddedicated the assets to utility service over their net book value in those assets. These unallocated acquisition adjustments included in other property, plant and equipment had an original cost of $156 million as of December 31, 20182021 and 2017, respectively,2020, and accumulated depreciation of $127$143 million and $122$140 million as of December 31, 20182021 and 2017,2020, respectively.
(4)Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include PacifiCorp's share of the expenses of these facilities.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 20182021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Facility | | Accumulated | | Construction |
| PacifiCorp | | in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Jim Bridger Nos. 1 - 4 | 67 | % | | $ | 1,523 | | | $ | 812 | | | $ | 15 | |
Hunter No. 1 | 94 | | | 489 | | | 221 | | | 8 | |
Hunter No. 2 | 60 | | | 306 | | | 138 | | | 1 | |
Wyodak | 80 | | | 477 | | | 269 | | | 8 | |
Colstrip Nos. 3 and 4 | 10 | | | 260 | | | 161 | | | 3 | |
Hermiston | 50 | | | 185 | | | 99 | | | — | |
Craig Nos. 1 and 2 | 19 | | | 369 | | | 319 | | | — | |
Hayden No. 1 | 25 | | | 77 | | | 47 | | | — | |
Hayden No. 2 | 13 | | | 44 | | | 28 | | | — | |
| | | | | | | |
Transmission and distribution facilities | Various | | 879 | | | 269 | | | 118 | |
Total | | | $ | 4,609 | | | $ | 2,363 | | | $ | 153 | |
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheets as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 11 | | | $ | 11 | |
Finance leases | 11 | | | 17 | |
Total right-of-use assets | $ | 22 | | | $ | 28 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 11 | | | $ | 11 | |
Finance leases | 12 | | | 17 | |
Total lease liabilities | $ | 23 | | | $ | 28 | |
|
| | | | | | | | | | | | | | |
| | | Facility | | Accumulated | | Construction |
| PacifiCorp | | in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Jim Bridger Nos. 1 - 4 | 67 | % | | $ | 1,458 |
| | $ | 647 |
| | $ | 11 |
|
Hunter No. 1 | 94 |
| | 484 |
| | 182 |
| | — |
|
Hunter No. 2 | 60 |
| | 298 |
| | 121 |
| | 5 |
|
Wyodak | 80 |
| | 471 |
| | 229 |
| | — |
|
Colstrip Nos. 3 and 4 | 10 |
| | 248 |
| | 137 |
| | 6 |
|
Hermiston | 50 |
| | 180 |
| | 87 |
| | 1 |
|
Craig Nos. 1 and 2 | 19 |
| | 367 |
| | 241 |
| | — |
|
Hayden No. 1 | 25 |
| | 74 |
| | 37 |
| | — |
|
Hayden No. 2 | 13 |
| | 43 |
| | 22 |
| | — |
|
Foote Creek | 79 |
| | 40 |
| | 27 |
| | 1 |
|
Transmission and distribution facilities | Various | | 808 |
| | 246 |
| | 76 |
|
Total | | | $ | 4,471 |
| | $ | 1,976 |
| | $ | 100 |
|
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 56 | | | $ | 60 | | | $ | 77 | |
Operating | 3 | | | 3 | | | 3 | |
Finance: | | | | | |
Amortization | 5 | | | 2 | | | 1 | |
Interest | 2 | | | 2 | | | 2 | |
Short-term | 3 | | | 1 | | | 2 | |
Total lease costs | $ | 69 | | | $ | 68 | | | $ | 85 | |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 12.7 | | 13.9 | | 14.0 |
Finance leases | 10.1 | | 8.4 | | 9.1 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 3.7 | % | | 3.8 | % | | 3.7 | % |
Finance leases | 11.1 | % | | 10.5 | % | | 10.6 | % |
(5)
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2021, 2020 and 2019.
PacifiCorp has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 3 | | | $ | 3 | | | $ | 6 | |
2023 | 2 | | | 2 | | | 4 | |
2024 | 1 | | | 2 | | | 3 | |
2025 | 1 | | | 2 | | | 3 | |
2026 | 1 | | | 2 | | | 3 | |
Thereafter | 6 | | | 10 | | | 16 | |
Total undiscounted lease payments | 14 | | | 21 | | | 35 | |
Less - amounts representing interest | (3) | | | (9) | | | (12) | |
Lease liabilities | $ | 11 | | | $ | 12 | | | $ | 23 | |
(6)Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2021 | | 2020 |
| | | | | |
| | | | | |
Employee benefit plans(1) | 17 years | | $ | 286 | | | $ | 432 | |
Utah mine disposition(2) | Various | | 116 | | | 117 | |
Unamortized contract values | 2 years | | 36 | | | 42 | |
Deferred net power costs | 2 years | | 151 | | | 78 | |
Unrealized loss on derivative contracts | N/A | | — | | | 17 | |
Environmental costs | 28 years | | 108 | | | 89 | |
Asset retirement obligation | 29 years | | 241 | | | 252 | |
Demand side management (DSM)(3) | 10 years | | 211 | | | 196 | |
Other | Various | | 203 | | | 172 | |
Total regulatory assets | | | $ | 1,352 | | | $ | 1,395 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 65 | | | $ | 116 | |
Noncurrent assets | | | 1,287 | | | 1,279 | |
Total regulatory assets | | | $ | 1,352 | | | $ | 1,395 | |
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2018 | | 2017 |
| | | | | |
Employee benefit plans(1) | 20 years | | $ | 448 |
| | $ | 418 |
|
Utah mine disposition(2) | Various | | 136 |
| | 156 |
|
Unamortized contract values | 5 years | | 79 |
| | 89 |
|
Deferred net power costs | 3 year | | 62 |
| | 21 |
|
Unrealized loss on derivative contracts | 2 years | | 96 |
| | 101 |
|
Asset retirement obligation | 31 years | | 119 |
| | 100 |
|
Other | Various | | 172 |
| | 176 |
|
Total regulatory assets | | | $ | 1,112 |
| | $ | 1,061 |
|
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 36 |
| | $ | 31 |
|
Noncurrent assets | | | 1,076 |
| | 1,030 |
|
Total regulatory assets | | | $ | 1,112 |
| | $ | 1,061 |
|
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.
| |
(1) | Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized. |
(2)Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the United Mine Workers of America ("UMWA") 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery.
| |
(2) | Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the net property, plant and equipment not considered probable of disallowance and for the portion of losses associated with the assets held for sale, UMWA 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery. |
(3)In accordance with the Utah general rate case order issued in December 2020, $185 million of amounts billed to Utah customers under the Utah STEP program were used to accelerate depreciation of certain coal-fueled generation units as discussed in Note 3.
PacifiCorp had regulatory assets not earning a return on investment of $636$723 million and $589$707 million as of December 31, 20182021 and 2017,2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2021 | | 2020 |
| | | | | |
Cost of removal(1) | 26 years | | $ | 1,187 | | | $ | 1,125 | |
Deferred income taxes(2) | Various | | 1,307 | | | 1,463 | |
| | | | | |
Unrealized gain on regulated derivatives | 1 year | | 53 | | | — | |
Other | Various | | 221 | | | 254 | |
Total regulatory liabilities | | | $ | 2,768 | | | $ | 2,842 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 118 | | | $ | 115 | |
Noncurrent liabilities | | | 2,650 | | | 2,727 | |
Total regulatory liabilities | | | $ | 2,768 | | | $ | 2,842 | |
(1)Amounts represent estimated costs, as generally accrued through depreciation rates, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable of being passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2018 | | 2017 |
| | | | | |
Cost of removal(1) | 26 years | | $ | 994 |
| | $ | 955 |
|
Deferred income taxes(2) | Various | | 1,803 |
| | 1,960 |
|
Other | Various | | 258 |
| | 156 |
|
Total regulatory liabilities | | | $ | 3,055 |
| | $ | 3,071 |
|
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 77 |
| | $ | 75 |
|
Noncurrent liabilities | | | 2,978 |
| | 2,996 |
|
Total regulatory liabilities | | | $ | 3,055 |
| | $ | 3,071 |
|
| |
(1) | Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost. |
| |
(2) | Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. See Note 8 for further discussion of 2017 Tax Reform. |
(6)(7)Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | |
2021: | | |
Credit facilities | | $ | 1,200 | |
Less: | | |
Short-term debt | | — | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | $ | 982 | |
| | |
2020: | | |
Credit facilities | | $ | 1,200 | |
Less: | | |
Short-term debt | | (93) | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | $ | 889 | |
|
| | | | |
2018: | | |
Credit facilities | | $ | 1,200 |
|
Less: | | |
Short-term debt | | (30 | ) |
Tax-exempt bond support | | (89 | ) |
Net credit facilities | | $ | 1,081 |
|
| | |
2017: | | |
Credit facilities | | $ | 1,000 |
|
Less: | | |
Short-term debt | | (80 | ) |
Tax-exempt bond support | | (130 | ) |
Net credit facilities | | $ | 790 |
|
As of December 31, 2021, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.
PacifiCorp has a $600 million$1.2 billion unsecured credit facility expiring in June 20212024 with a one-year extension option subject to lender consent and a $600 million unsecured credit facility expiring in June 2021 with two one-yearan unlimited number of maturity extension options, subject to lender consent. TheseThe credit facilities,facility, which supportsupports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provideprovides for the issuance of letters of credit, havehas a variable interest ratesrate based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.
As of December 31, 2018 and 2017, the2021, PacifiCorp did not have any commercial paper borrowings outstanding. As of December 31, 2020, PacifiCorp had $93 million of commercial paper outstanding with a weighted average interest rate on commercial paper borrowings outstanding was 2.85% and 1.83%, respectively. Theseof 0.16%.
The credit facilities requirefacility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
As of December 31, 20182021 and 2017,2020, PacifiCorp had $184$19 million and $230$11 million, respectively, of fully available letters of credit issued under committed arrangements. Asarrangements in support of December 31, 2018 and 2017, $170 million and $216 million, respectively, of these letters of credit, support PacifiCorp's variable-rate tax-exempt bond obligations and expire in March 2019 and $14 million support certain transactions required by third parties and generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
(7)
(8)Long-term Debt and Capital Lease Obligations
PacifiCorp's long-term debt and capital lease obligations werewas as follows as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| | | | | Average | | | | Average |
| Principal | | Carrying | | Interest | | Carrying | | Interest |
| Amount | | Value | | Rate | | Value | | Rate |
| | | | | | | | | |
First mortgage bonds: | | | | | | | | | |
2.95% to 8.53%, due through 2026 | $ | 1,379 | | | $ | 1,378 | | | 4.52 | % | | $ | 2,245 | | | 4.12 | % |
2.70% to 7.70%, due 2027 to 2031 | 1,100 | | | 1,094 | | | 4.35 | | | 1,094 | | | 4.35 | |
5.25% to 6.10%, due 2032 to 2036 | 850 | | | 845 | | | 5.75 | | | 845 | | | 5.75 | |
5.75% to 6.35%, due 2037 to 2041 | 2,150 | | | 2,137 | | | 6.05 | | | 2,137 | | | 6.05 | |
4.10% due 2042 | 300 | | | 297 | | | 4.10 | | | 297 | | | 4.10 | |
2.90% to 4.15%, due 2049 to 2052 | 2,800 | | | 2,761 | | | 3.52 | | | 1,776 | | | 3.86 | |
Variable-rate series, tax-exempt bond obligations (2021-0.12% to 0.13%; 2020-0.14% to 0.16%): | | | | | | | | | |
Due 2025 | 25 | | | 25 | | | 0.12 | | | 25 | | | 0.14 | |
Due 2024 to 2025(1) | 193 | | | 193 | | | 0.13 | | | 193 | | | 0.15 | |
Total long-term debt | $ | 8,797 | | | $ | 8,730 | | | | | $ | 8,612 | | | |
|
| | | | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| | | | | Average | | | | Average |
| Principal | | Carrying | | Interest | | Carrying | | Interest |
| Amount | | Value | | Rate | | Value | | Rate |
| | | | | | | | | |
First mortgage bonds: | | | | | | | | | |
2.95% to 8.53%, due through 2023 | $ | 1,824 |
| | $ | 1,821 |
| | 4.48 | % | | $ | 2,320 |
| | 4.73 | % |
3.35% to 6.71%, due 2024 to 2026 | 775 |
| | 771 |
| | 3.92 |
| | 771 |
| | 3.92 |
|
7.70% due 2031 | 300 |
| | 298 |
| | 7.70 |
| | 298 |
| | 7.70 |
|
5.25% to 6.35%, due 2034 to 2038 | 2,350 |
| | 2,338 |
| | 5.96 |
| | 2,337 |
| | 5.96 |
|
4.10% to 6.00%, due 2039 to 2042 | 950 |
| | 939 |
| | 5.40 |
| | 938 |
| | 5.40 |
|
4.125%, due 2049 | 600 |
| | 593 | | 4.13 |
| | — |
| | — |
|
Variable-rate series, tax-exempt bond obligations (2018-1.67% to 1.85%; 2017-1.60% to 1.87%): | | | | | | | | | |
Due 2018 to 2020 | 38 |
| | 38 |
| | 1.85 |
| | 79 |
| | 1.77 |
|
Due 2018 to 2025(1) | 25 |
| | 25 |
| | 1.75 |
| | 70 |
| | 1.81 |
|
Due 2024(1)(2) | 143 |
| | 142 |
| | 1.68 |
| | 142 |
| | 1.73 |
|
Due 2024 to 2025(2) | 50 |
| | 50 |
| | 1.75 |
| | 50 |
| | 1.72 |
|
Total long-term debt | 7,055 |
| | 7,015 |
| | | | 7,005 |
| | |
Capital lease obligations: | | | | | | | | | |
8.75% to 14.61%, due through 2035 | 21 |
| | 21 |
| | 10.55 |
| | 20 |
| | 11.46 |
|
Total long-term debt and capital lease | | | | | | | | | |
obligations | $ | 7,076 |
| | $ | 7,036 |
| | | | $ | 7,025 |
| | |
| | | | | | | | | | | |
Reflected as: | | | |
| 2021 | | 2020 |
Current portion of long-term debt | $ | 155 | | | $ | 420 | |
Long-term debt | 8,575 | | | 8,192 | |
Total long-term debt | $ | 8,730 | | | $ | 8,612 | |
|
| | | | | | | |
Reflected as: | | | |
| 2018 | | 2017 |
| | | |
Current portion of long-term debt and capital lease obligations | $ | 352 |
| | $ | 588 |
|
Long-term debt and capital lease obligations | 6,684 |
| | 6,437 |
|
Total long-term debt and capital lease obligations | $ | 7,036 |
| | $ | 7,025 |
|
(1)Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
| |
1) | Supported by $170 million and $216 million of fully available letters of credit issued under committed bank arrangements as of December 31, 2018 and 2017, respectively. |
| |
2) | Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations. |
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the United States Securities and Exchange Commission (SEC) to issue up to $2.0 billion additionalan indeterminate amount of first mortgage bonds through October 2021.September 2023.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $28$31 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2018.2021.
In November 2021, PacifiCorp has entered into long-term agreements that qualify as capital leases and expire at various dates through March 2035 for transportation services, a power purchase agreement and real estate. The transportation services agreements included as capital leases are for the right to use pipeline facilities to provide natural gas to two of PacifiCorp's generating facilities. Net capital lease assets of $21 million and $20 million as of December 31, 2018 and 2017, respectively, were included in property, plant and equipment, netexercised its par call redemption option, available in the Consolidated Balance Sheets.final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
As of December 31, 2018,2021, the annual principal maturities of long-term debt and total capital lease obligations for 20192022 and thereafter are as follows (in millions):
| | | | | |
| Long-term |
| Debt |
| |
2022 | $ | 155 | |
2023 | 449 | |
2024 | 591 | |
2025 | 302 | |
2026 | 100 | |
Thereafter | 7,200 | |
Total | 8,797 | |
Unamortized discount and debt issuance costs | (67) | |
| |
Total | $ | 8,730 | |
|
| | | | | | | | | | | |
| Long-term | | Capital Lease | | |
| Debt | | Obligations | | Total |
| | | | | |
2019 | $ | 350 |
| | $ | 4 |
| | $ | 354 |
|
2020 | 38 |
| | 3 |
| | 41 |
|
2021 | 420 |
| | 7 |
| | 427 |
|
2022 | 605 |
| | 3 |
| | 608 |
|
2023 | 449 |
| | 2 |
| | 451 |
|
Thereafter | 5,193 |
| | 16 |
| | 5,209 |
|
Total | 7,055 |
| | 35 |
| | 7,090 |
|
Unamortized discount and debt issuance costs | (40 | ) | | — |
| | (40 | ) |
Amounts representing interest | — |
| | (14 | ) | | (14 | ) |
Total | $ | 7,015 |
| | $ | 21 |
| | $ | 7,036 |
|
(8)(9)Income Taxes
Tax Cuts and Jobs Act
The Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform") impacted many areas of income tax law. The most material items included the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018 and limitations on bonus depreciation for utility property.
In December 2017, the SEC issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. On December 31, 2017, PacifiCorp recorded the impacts of the 2017 Tax Reform and believed all the impacts to be complete with the exception of interpretations of the bonus depreciation rules. PacifiCorp determined the amounts recorded and the interpretations relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. PacifiCorp believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, PacifiCorp finalized its provisional amounts recording a current tax benefit and deferred tax expense of $21 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform and PacifiCorp's regulatory nature, PacifiCorp reduced the associated deferred income tax liabilities $8 million and increased regulatory liabilities by the same amount.
Income tax (benefit) expense (benefit) consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current: | | | | | |
Federal | $ | (150) | | | $ | 19 | | | $ | 158 | |
State | 7 | | | 30 | | | 34 | |
Total | (143) | | | 49 | | | 192 | |
| | | | | |
Deferred: | | | | | |
Federal | 26 | | | (124) | | | (132) | |
State | 40 | | | 1 | | | 4 | |
Total | 66 | | | (123) | | | (128) | |
| | | | | |
Investment tax credits | (2) | | | (1) | | | (3) | |
Total income tax (benefit) expense | $ | (79) | | | $ | (75) | | | $ | 61 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Current: | | | | | |
Federal | $ | 164 |
| | $ | 249 |
| | $ | 169 |
|
State | 40 |
| | 41 |
| | 32 |
|
Total | 204 |
| | 290 |
| | 201 |
|
| | | | | |
Deferred: | | | | | |
Federal | (187 | ) | | 59 |
| | 123 |
|
State | (9 | ) | | 15 |
| | 21 |
|
Total | (196 | ) | | 74 |
| | 144 |
|
| | | | | |
Investment tax credits | (3 | ) | | (4 | ) | | (5 | ) |
Total income tax expense | $ | 5 |
| | $ | 360 |
| | $ | 340 |
|
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
State income taxes, net of federal income tax benefit | 3 | | | 3 | | | 3 | |
Effects of ratemaking | (14) | | | (22) | | | (13) | |
Federal income tax credits | (20) | | | (13) | | | (3) | |
Other | — | | | — | | | (1) | |
Effective income tax rate | (10) | % | | (11) | % | | 7 | % |
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
State income taxes, net of federal income tax benefit | 4 |
| | 3 |
| | 3 |
|
Amortization of excess deferred income taxes | (17 | ) | | — |
| | — |
|
Federal income tax credits | (7 | ) | | (5 | ) | | (6 | ) |
Other | — |
| | (1 | ) | | (1 | ) |
Effective income tax rate | 1 | % | | 32 | % | | 31 | % |
Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity production tax creditsPTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. Amortization
Effects of excess deferred income taxesratemaking is primarily attributable to the amortization of $127 million of Utah allocatedactivity associated with excess deferred income taxes pursuanttaxes. Excess deferred income tax amortization, net of deferrals, was $112 million for 2021, including the use of $4 million to a 2017 Tax Reform settlement approved byamortize certain regulatory asset balances in Wyoming and Idaho. Excess deferred income tax amortization, net of deferrals, was $132 million for 2020, including the UPSC, whereby a portionuse of Utah allocated excess$118 million to accelerate depreciation of certain retired equipment and to amortize certain regulatory balances in Idaho, Oregon and Utah. Excess deferred income taxes amortization, net of deferrals, was used$93 million for 2019, including the use of $91 million to accelerate depreciation on Utah's share of certain thermal plant units.retired wind equipment for Oregon.
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 682 | | | $ | 700 | |
Employee benefits | 68 | | | 93 | |
| | | |
State carryforwards | 73 | | | 73 | |
Loss contingencies | 63 | | | 63 | |
Asset retirement obligations | 73 | | | 65 | |
Other | 73 | | | 83 | |
| 1,032 | | | 1,077 | |
Deferred income tax liabilities: | | | |
Property, plant and equipment | (3,468) | | | (3,311) | |
Regulatory assets | (332) | | | (343) | |
Other | (79) | | | (50) | |
| (3,879) | | | (3,704) | |
Net deferred income tax liability | $ | (2,847) | | | $ | (2,627) | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 752 |
| | $ | 756 |
|
Employee benefits | 91 |
| | 84 |
|
Derivative contracts and unamortized contract values | 45 |
| | 48 |
|
State carryforwards | 77 |
| | 83 |
|
Asset retirement obligations | 53 |
| | 50 |
|
Other | 56 |
| | 50 |
|
| 1,074 |
| | 1,071 |
|
Deferred income tax liabilities: | | | |
Property, plant and equipment | (3,335 | ) | | (3,381 | ) |
Regulatory assets | (273 | ) | | (261 | ) |
Other | (9 | ) | | (11 | ) |
| (3,617 | ) | | (3,653 | ) |
Net deferred income tax liability | $ | (2,543 | ) | | $ | (2,582 | ) |
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 20182021 (in millions):
| | | | | | | | |
| | State |
| | |
Net operating loss carryforwards | | $ | 1,138 | |
Deferred income taxes on net operating loss carryforwards | | $ | 53 | |
Expiration dates | | 2023 - 2032 |
| | |
Tax credit carryforwards | | $ | 20 | |
Expiration dates | | 2022 - indefinite |
|
| | | | |
| | State |
| | |
Net operating loss carryforwards | | $ | 1,230 |
|
Deferred income taxes on net operating loss carryforwards | | $ | 58 |
|
Expiration dates | | 2019 - 2032 |
|
| | |
Tax credit carryforwards | | $ | 19 |
|
Expiration dates | | 2019 - indefinite |
|
The United States Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns through December 31, 2011.2013. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31, 2009,2011, with the exception of Idaho, for whichwhere the statute of limitations has expired through December 31, 2014, except2017, for the impact of anyall adjustments other than federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
As of December 31, 2018 and 2017, PacifiCorp had unrecognized tax benefits totaling $1 million and $10 million, respectively, related to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect PacifiCorp's effective income tax rate.
(10) Employee Benefit Plans | |
(9) | Employee Benefit Plans
|
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover the majoritycertain of its employees, as well as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.
Defined Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, collectively the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.
During 2018, the Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Pension Settlement
Pension settlement accounting was triggered in 2021 as a result of the amount of lump sum distributions in the Retirement Plan during 2021 exceeding the service and interest cost threshold. This resulted in an interim July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the settlement accounting, PacifiCorp recognized settlement losses of $6 million, net of regulatory deferrals during the year ended December 31, 2021.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | | $ | 2 | |
Interest cost | 29 | | | 36 | | | 44 | | | 7 | | | 9 | | | 12 | |
Expected return on plan assets | (51) | | | (56) | | | (67) | | | (9) | | | (14) | | | (21) | |
Settlement | 6 | | | — | | | — | | | — | | | — | | | — | |
Net amortization | 21 | | | 18 | | | 11 | | | 1 | | | 3 | | | — | |
Net periodic benefit cost (credit) | $ | 5 | | | $ | (2) | | | $ | (12) | | | $ | 1 | | | $ | — | | | $ | (7) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | |
Service cost | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
Interest cost | 43 |
| | 49 |
| | 54 |
| | 11 |
| | 14 |
| | 15 |
|
Expected return on plan assets | (72 | ) | | (72 | ) | | (75 | ) | | (21 | ) | | (21 | ) | | (21 | ) |
Settlement | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net amortization | 13 |
| | 14 |
| | 34 |
| | (6 | ) | | (6 | ) | | (5 | ) |
Net periodic benefit cost (credit) | $ | 6 |
| | $ | (9 | ) | | $ | 17 |
| | $ | (14 | ) | | $ | (11 | ) | | $ | (9 | ) |
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 1,064 | | | $ | 1,036 | | | $ | 327 | | | $ | 334 | |
Employer contributions(1) | 5 | | | 5 | | | 1 | | | — | |
Participant contributions | — | | | — | | | 6 | | | 4 | |
Actual return on plan assets | 109 | | | 124 | | | 14 | | | 15 | |
Settlement(2) | (52) | | | — | | | — | | | — | |
Benefits paid | (68) | | | (101) | | | (24) | | | (26) | |
Plan assets at fair value, end of year | $ | 1,058 | | | $ | 1,064 | | | $ | 324 | | | $ | 327 | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 1,111 |
| | $ | 999 |
| | $ | 332 |
| | $ | 302 |
|
Employer contributions | 4 |
| | 54 |
| | 1 |
| | 1 |
|
Participant contributions | — |
| | — |
| | 5 |
| | 7 |
|
Actual return on plan assets | (52 | ) | | 166 |
| | (16 | ) | | 49 |
|
Settlement | (52 | ) | | — |
| | — |
| | — |
|
Benefits paid | (69 | ) | | (108 | ) | | (25 | ) | | (27 | ) |
Plan assets at fair value, end of year | $ | 942 |
| | $ | 1,111 |
| | $ | 297 |
| | $ | 332 |
|
(1)Amounts represent employer contributions to the SERP.
(2)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 1,202 | | | $ | 1,167 | | | $ | 307 | | | $ | 304 | |
Service cost | — | | | — | | | 2 | | | 2 | |
Interest cost | 29 | | | 36 | | | 7 | | | 9 | |
Participant contributions | — | | | — | | | 6 | | | 4 | |
Actuarial (gain) loss | (63) | | | 100 | | | (10) | | | 14 | |
| | | | | | | |
Settlement(1) | (52) | | | — | | | — | | | — | |
| | | | | | | |
Benefits paid | (68) | | | (101) | | | (24) | | | (26) | |
Benefit obligation, end of year | $ | 1,048 | | | $ | 1,202 | | | $ | 288 | | | $ | 307 | |
Accumulated benefit obligation, end of year | $ | 1,048 | | | $ | 1,202 | | | | | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 1,251 |
| | $ | 1,276 |
| | $ | 331 |
| | $ | 358 |
|
Service cost | — |
| | — |
| | 2 |
| | 2 |
|
Interest cost | 43 |
| | 49 |
| | 11 |
| | 14 |
|
Participant contributions | — |
| | — |
| | 5 |
| | 7 |
|
Actuarial (gain) loss | (68 | ) | | 34 |
| | (26 | ) | | (23 | ) |
Settlement | (52 | ) | | — |
| | | | — |
|
Benefits paid | (69 | ) | | (108 | ) | | (25 | ) | | (27 | ) |
Benefit obligation, end of year | $ | 1,105 |
| | $ | 1,251 |
| | $ | 298 |
| | $ | 331 |
|
Accumulated benefit obligation, end of year | $ | 1,105 |
| | $ | 1,251 |
| | | | |
(1)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 1,058 | | | $ | 1,064 | | | $ | 324 | | | $ | 327 | |
Less - Benefit obligation, end of year | 1,048 | | | 1,202 | | | 288 | | | 307 | |
Funded status | $ | 10 | | | $ | (138) | | | $ | 36 | | | $ | 20 | |
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 63 | | | $ | 8 | | | $ | 36 | | | $ | 20 | |
Accrued employee expenses | (4) | | | (4) | | | — | | | — | |
Other long-term liabilities | (49) | | | (142) | | | — | | | — | |
Amounts recognized | $ | 10 | | | $ | (138) | | | $ | 36 | | | $ | 20 | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 942 |
| | $ | 1,111 |
| | $ | 297 |
| | $ | 332 |
|
Less - Benefit obligation, end of year | 1,105 |
| | 1,251 |
| | 298 |
| | 331 |
|
Funded status | $ | (163 | ) | | $ | (140 | ) | | $ | (1 | ) | | $ | 1 |
|
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 3 |
| | $ | 5 |
| | $ | — |
| | $ | 1 |
|
Other current liabilities | (4 | ) | | (4 | ) | | — |
| | — |
|
Other long-term liabilities | (162 | ) | | (141 | ) | | (1 | ) | | — |
|
Amounts recognized | $ | (163 | ) | | $ | (140 | ) | | $ | (1 | ) | | $ | 1 |
|
The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $52$69 million and $60$61 million as of December 31, 20182021 and 2017,2020, respectively. These assets are not included in the plan assets in the above table, but are reflected in cash and cash equivalents, totaling $1 million and $9 millionnoncurrent other assets as of December 31, 20182021 and 2017,2020, respectively, and noncurrent other assets, totaling $51 million as of December 31, 2018 and 2017 on the Consolidated Balance Sheets.
The projected benefit obligation for the pension and other postretirement plans were in excessAs of December 31, 2021, the fair value of their respective plansthe plan assets as of December 31, 2018. The accumulated benefit obligation for the pension plansRetirement Plan was in excess of both the fair value of plan assets as of December 31, 2018.projected benefit obligation and the accumulated benefit obligation.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net loss (gain) | $ | 298 | | | $ | 455 | | | $ | (28) | | | $ | (13) | |
| | | | | | | |
Regulatory deferrals(1) | 11 | | | 2 | | | 2 | | | 3 | |
Total | $ | 309 | | | $ | 457 | | | $ | (26) | | | $ | (10) | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Net loss (gain) | $ | 461 |
| | $ | 442 |
| | $ | (2 | ) | | $ | (12 | ) |
Prior service credit | — |
| | — |
| | — |
| | (6 | ) |
Regulatory deferrals | (1 | ) | | (4 | ) | | 7 |
| | 7 |
|
Total | $ | 460 |
| | $ | 438 |
| | $ | 5 |
| | $ | (11 | ) |
(1)Includes $9 million of deferrals associated with 2021 pension settlement losses.
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 20182021 and 20172020 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | | | Comprehensive | | |
| Asset | | | | Loss | | Total |
Pension | | | | | | | |
Balance, December 31, 2019 | $ | 422 | | | | | $ | 21 | | | $ | 443 | |
Net loss arising during the year | 27 | | | | | 5 | | | 32 | |
| | | | | | | |
Net amortization | (17) | | | | | (1) | | | (18) | |
| | | | | | | |
Total | 10 | | | | | 4 | | | 14 | |
Balance, December 31, 2020 | 432 | | | | | 25 | | | 457 | |
Net gain arising during the year | (120) | | | | | (1) | | | (121) | |
| | | | | | | |
Net amortization | (20) | | | | | (1) | | | (21) | |
Settlement | (6) | | | | | — | | | (6) | |
Total | (146) | | | | | (2) | | | (148) | |
Balance, December 31, 2021 | $ | 286 | | | | | $ | 23 | | | $ | 309 | |
|
| | | | | | | | | | | |
| | | Accumulated | | |
| | | Other | | |
| Regulatory | | Comprehensive | | |
| Asset | | Loss | | Total |
Pension | | | | | |
Balance, December 31, 2016 | $ | 491 |
| | $ | 20 |
| | $ | 511 |
|
Net (gain) loss arising during the year | (60 | ) | | 1 |
| | (59 | ) |
Net amortization | (13 | ) | | (1 | ) | | (14 | ) |
Total | (73 | ) | | — |
| | (73 | ) |
Balance, December 31, 2017 | 418 |
| | 20 |
| | 438 |
|
Net loss (gain) arising during the year | 59 |
| | (2 | ) | | 57 |
|
Net amortization | (12 | ) | | (1 | ) | | (13 | ) |
Settlement | (22 | ) | | — |
| | (22 | ) |
Total | 25 |
| | (3 | ) | | 22 |
|
Balance, December 31, 2018 | $ | 443 |
| | $ | 17 |
| | $ | 460 |
|
| | | | | |
| Regulatory |
| Liability |
Other Postretirement | |
Balance, December 31, 2019 | $ | (20) | |
Net loss arising during the year | 13 | |
| |
Net amortization | (3) | |
Total | 10 | |
Balance, December 31, 2020 | (10) | |
Net gain arising during the year | (15) | |
| |
Net amortization | (1) | |
Total | (16) | |
Balance, December 31, 2021 | $ | (26) | |
|
| | | |
| Regulatory |
| Asset (Liability) |
Other Postretirement | |
Balance, December 31, 2016 | $ | 34 |
|
Net gain arising during the year | (51 | ) |
Net amortization | 6 |
|
Total | (45 | ) |
Balance, December 31, 2017 | (11 | ) |
Net loss arising during the year | 10 |
|
Net amortization | 6 |
|
Total | 16 |
|
Balance, December 31, 2018 | $ | 5 |
|
Plan Assumptions
Weighted-average assumptionsAssumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 2.90 | % | | 2.50 | % | | 3.25 | % | | 2.90 | % | | 2.50 | % | | 3.20 | % |
Rate of compensation increase | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan - non-union | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.40 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.27 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2021 | 0.82 | % | | 0.82 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2022 | 0.88 | % | | 0.82 | % | | 2.10 | % | | N/A | | N/A | | N/A |
2023 | 0.88 | % | | 2.00 | % | | 2.10 | % | | N/A | | N/A | | N/A |
2024 and beyond | 1.90 | % | | 2.00 | % | | 2.10 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Interest crediting rates for cash balance plan - union | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.15 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.16 | % | | 2.16 | % | | N/A | | N/A | | N/A |
2021 | 1.42 | % | | 1.42 | % | | 2.16 | % | | N/A | | N/A | | N/A |
2022 | 1.94 | % | | 1.42 | % | | 2.70 | % | | N/A | | N/A | | N/A |
2023 | 1.94 | % | | 2.40 | % | | 2.70 | % | | N/A | | N/A | | N/A |
2024 and beyond | 2.30 | % | | 2.40 | % | | 2.70 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | |
Discount rate | 2.50 | % | | 3.25 | % | | 4.25 | % | | 2.50 | % | | 3.20 | % | | 4.25 | % |
Expected return on plan assets | 6.00 | | | 6.50 | | | 7.00 | | | 2.90 | | | 4.92 | | | 6.86 | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 4.25 | % | | 3.60 | % | | 4.05 | % | | 4.25 | % | | 3.60 | % | | 4.05 | % |
Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
| | N/A |
|
| | | | | | | | | | | |
Interest crediting rates for cash balance plan (1)(2)(3) | 3.40 | % | | 1.61 | % | | 2.06 | % | | N/A |
| | N/A |
| | N/A |
|
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | |
Discount rate | 3.60 | % | | 4.05 | % | | 4.40 | % | | 3.60 | % | | 4.05 | % | | 4.35 | % |
Expected return on plan assets | 7.00 |
| | 7.25 |
| | 7.50 |
| | 6.86 |
| | 7.25 |
| | 7.50 |
|
Rate of compensation increase | N/A |
| | N/A |
| | 2.75 |
| | N/A |
| | N/A |
| | N/A |
|
| |
(1) | 2018 Cash Balance Interest Crediting Rate assumption is 3.40% for 2019 and all future years for nonunion participants and 3.15% for 2019-2020 and 3.25% for 2021+ for union participants. |
| |
(2) | 2017 Cash Balance Interest Crediting Rate assumption was 2.26% for 2018-2019 and 1.60% for 2020+ for nonunion participants and 2.78% for 2018-2019 and 2.60% for 2020+ for union participants. |
| |
(3) | 2016 Cash Balance Interest Crediting Rate assumption was 1.44% for 2017-2018 and 2.05% for 2019+ for nonunion participants and 2.35% for 2017-2018 and 3.05% for 2019+ for union participants. |
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
As a result of a plan amendment effective on January 1, 2017, the benefit obligation for the Retirement Plan is no longer affected by future increases in compensation. As a result of a labor settlement reached with UMWA in December 2014, the benefit obligation for the other postretirement plan is no longer affected by healthcare cost trends.
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $0$— million, respectively, during 2019.2022. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension Protection Act of 2006, as amended ("PPA"PPA of 2006"). PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the PPA. PacifiCorp's fundingPPA of 2006. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan is subject to tax deductibility and subordination limits and other considerations.plan.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 20192022 through 20232026 and for the five years thereafter are summarized below (in millions):
| | | | | | | | | | | |
| Projected Benefit Payments |
| Pension | | Other Postretirement |
| | | |
2022 | $ | 96 | | | $ | 24 | |
2023 | 85 | | | 23 | |
2024 | 79 | | | 22 | |
2025 | 76 | | | 21 | |
2026 | 71 | | | 20 | |
2027-2031 | 304 | | | 87 | |
|
| | | | | | | |
| Projected Benefit Payments |
| Pension | | Other Postretirement |
| | | |
2019 | $ | 105 |
| | $ | 24 |
|
2020 | 102 |
| | 26 |
|
2021 | 98 |
| | 23 |
|
2022 | 92 |
| | 22 |
|
2023 | 88 |
| | 21 |
|
2024-2028 | 369 |
| | 95 |
|
Plan Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the PacifiCorp PensionBerkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
In 2020, the assets of the PacifiCorp Master Retirement Trust were transferred into the BHE Master Retirement Trust.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2018:
| | | | | | | | | | | |
| Pension(1) | | Other Postretirement(1) |
| % | | % |
Debt securities(2) | 55 - 85 | | 70 - 80 |
Equity securities(2) | 25- 35 | | 20 - 30 |
Other | 0 - 10 | | 0 - 1 |
| | | |
| Pension(1)
| | Other Postretirement(1)
|
| % | | % |
Debt securities(2)
| 30 - 43 | | 33 - 37 |
Equity securities(2)
| 48 - 65 | | 62 - 66 |
Limited partnership interests | 6 - 12 | | 1 - 3 |
| |
(1) | PacifiCorp's Retirement Plan trust includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts. |
| |
(2) | For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities. |
(1)The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2021: | | | | | | | | |
Cash equivalents | | $ | — | | | $ | 15 | | | $ | — | | | $ | 15 | |
Debt securities: | | | | | | | | |
United States government obligations | | 51 | | | — | | | — | | | 51 | |
| | | | | | | | |
Corporate obligations | | — | | | 299 | | | — | | | 299 | |
Municipal obligations | | — | | | 22 | | | — | | | 22 | |
Agency, asset and mortgage-backed obligations | | — | | | 38 | | | — | | | 38 | |
Equity securities: | | | | | | | | |
United States companies | | 61 | | | — | | | — | | | 61 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 112 | | | $ | 374 | | | $ | — | | | $ | 486 | |
Investment funds(2) measured at net asset value | | | | | | | | 538 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 34 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 1,058 | |
| | | | | | | | |
As of December 31, 2020: | | | | | | | | |
Cash equivalents | | $ | — | | | $ | 32 | | | $ | — | | | $ | 32 | |
Debt securities: | | | | | | | | |
United States government obligations | | 14 | | | — | | | — | | | 14 | |
International government obligations | | — | | | — | | | — | | | — | |
Corporate obligations | | — | | | 231 | | | — | | | 231 | |
Municipal obligations | | — | | | 21 | | | — | | | 21 | |
| | | | | | | | |
Equity securities: | | | | | | | | |
United States companies | | 91 | | | — | | | — | | | 91 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 105 | | | $ | 284 | | | $ | — | | | $ | 389 | |
Investment funds(2) measured at net asset value | | | | | | | | 587 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 88 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 1,064 | |
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 59% and 41%, respectively, for 2021 and 78% and 22%, respectively, for 2020, and are invested in United States and international securities of approximately 84% and 16%, respectively, for 2021 and 74% and 26%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate.
|
| | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2018: | | | | | | | | |
Cash equivalents | | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | 11 |
|
Debt securities: | | | | | | | | |
United States government obligations | | 4 |
| | — |
| | — |
| | 4 |
|
International government obligations | | — |
| | 1 |
| | — |
| | 1 |
|
Corporate obligations | | — |
| | 88 |
| | — |
| | 88 |
|
Municipal obligations | | — |
| | 10 |
| | — |
| | 10 |
|
Agency, asset and mortgage-backed obligations | | — |
| | 43 |
| | — |
| | 43 |
|
Equity securities: | | | | | | | | |
United States companies | | 327 |
| | — |
| | — |
| | 327 |
|
International companies | | 15 |
| | — |
| | — |
| | 15 |
|
Investment funds(2) | | 54 |
| | — |
| | — |
| | 54 |
|
Total assets in the fair value hierarchy | | $ | 400 |
| | $ | 153 |
| | $ | — |
| | 553 |
|
Investment funds(2) measured at net asset value | | | | | | | | 285 |
|
Limited partnership interests(3) measured at net asset value | | | | | | | | 104 |
|
Investments at fair value | | | | | | | | $ | 942 |
|
| | | | | | | | |
As of December 31, 2017: | | | | | | | | |
Cash equivalents | | $ | — |
| | $ | 43 |
| | $ | — |
| | $ | 43 |
|
Debt securities: | | | | | | | | |
United States government obligations | | 45 |
| | — |
| | — |
| | 45 |
|
Corporate obligations | | — |
| | 60 |
| | — |
| | 60 |
|
Municipal obligations | | — |
| | 9 |
| | — |
| | 9 |
|
Agency, asset and mortgage-backed obligations | | — |
| | 37 |
| | — |
| | 37 |
|
Equity securities: | | | | | | | | |
United States companies | | 416 |
| | — |
| | — |
| | 416 |
|
International companies | | 22 |
| | — |
| | — |
| | 22 |
|
Total assets in the fair value hierarchy | | $ | 483 |
| | $ | 149 |
| | $ | — |
| | 632 |
|
Investment funds(2) measured at net asset value | | | | | | | | 416 |
|
Limited partnership interests(3) measured at net asset value | | | | | | | | 63 |
|
Investments at fair value | | | | | | | | $ | 1,111 |
|
| |
(1) | Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
|
| |
(2) | Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 55% and 45% respectively, for 2018 and 60% and 40%, respectively, for 2017, and are invested in United States and international securities of approximately 68% and 32%, respectively, for 2018 and 57% and 43%, respectively, for 2017.
|
| |
(3) | Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital. |
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2021: | | | | | | | | |
Cash and cash equivalents | | $ | 4 | | | $ | 1 | | | $ | — | | | $ | 5 | |
Debt securities: | | | | | | | | |
United States government obligations | | 24 | | | — | | | — | | | 24 | |
| | | | | | | | |
Corporate obligations | | — | | | 79 | | | — | | | 79 | |
Municipal obligations | | — | | | 15 | | | — | | | 15 | |
Agency, asset and mortgage-backed obligations | | — | | | 35 | | | — | | | 35 | |
Equity securities: | | | | | | | | |
United States companies | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 32 | | | $ | 130 | | | $ | — | | | 162 | |
Investment funds(2) measured at net asset value | | | | | | | | 161 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 1 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 324 | |
| | | | | | | | |
As of December 31, 2020: | | | | | | | | |
Cash and cash equivalents | | $ | 8 | | | $ | 1 | | | $ | — | | | $ | 9 | |
Debt securities: | | | | | | | | |
United States government obligations | | 11 | | | — | | | — | | | 11 | |
| | | | | | | | |
Corporate obligations | | — | | | 86 | | | — | | | 86 | |
Municipal obligations | | — | | | 16 | | | — | | | 16 | |
Agency, asset and mortgage-backed obligations | | — | | | 44 | | | — | | | 44 | |
Equity securities: | | | | | | | | |
United States companies | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 23 | | | $ | 147 | | | $ | — | | | 170 | |
Investment funds(2) measured at net asset value | | | | | | | | 153 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 4 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 327 | |
|
| | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2018: | | | | | | | | |
Cash and cash equivalents | | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 5 |
|
Debt securities: | | | | | | | | |
United States government obligations | | 3 |
| | — |
| | — |
| | 3 |
|
Corporate obligations | | — |
| | 23 |
| | — |
| | 23 |
|
Municipal obligations | | — |
| | 2 |
| | — |
| | 2 |
|
Agency, asset and mortgage-backed obligations | | — |
| | 17 |
| | — |
| | 17 |
|
Equity securities: | | | | | | | | |
United States companies | | 83 |
| | — |
| | — |
| | 83 |
|
International companies | | 4 |
| | — |
| | — |
| | 4 |
|
Investment funds(2) | | 38 |
| | — |
| | — |
| | 38 |
|
Total assets in the fair value hierarchy | | 132 |
| | 43 |
| | — |
| | 175 |
|
Investment funds(2) measured at net asset value | | | | | | | | 116 |
|
Limited partnership interests(3) measured at net asset value | | | | | | | | 6 |
|
Investments at fair value | | | | | | | | $ | 297 |
|
| | | | | | | | |
As of December 31, 2017: | | | | | | | | |
Cash and cash equivalents | | $ | 4 |
| | $ | 3 |
| | $ | — |
| | $ | 7 |
|
Debt securities: | | | | | | | | |
United States government obligations | | 11 |
| | — |
| | — |
| | 11 |
|
Corporate obligations | | — |
| | 16 |
| | — |
| | 16 |
|
Municipal obligations | | — |
| | 2 |
| | — |
| | 2 |
|
Agency, asset and mortgage-backed obligations | | — |
| | 16 |
| | — |
| | 16 |
|
Equity securities: | | | | | | | | |
United States companies | | 98 |
| | — |
| | — |
| | 98 |
|
International companies | | 6 |
| | — |
| | — |
| | 6 |
|
Investment funds(2) | | 32 |
| | — |
| | — |
| | 32 |
|
Total assets in the fair value hierarchy | | 151 |
| | 37 |
| | — |
| | 188 |
|
Investment funds(2) measured at net asset value | | | | | | | | 140 |
|
Limited partnership interests(3) measured at net asset value | | | | | | | | 4 |
|
Investments at fair value | | | | | | | | $ | 332 |
|
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
| |
(1) | Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 39% and 61%, respectively, for 2021 and 38% and 62%, respectively, for 2020, and are invested in United States and international securities of approximately 90% and 10%, respectively, for 2021 and 93% and 7%, respectively, for 2020. (3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
|
| |
(2) | Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 59% and 41%, respectively, for 2018 and 63% and 37%, respectively, for 2017, and are invested in United States and international securities of approximately 90% and 10%, respectively, for 2018 and 77% and 23%, respectively, for 2017.
|
| |
(3) | Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital. |
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Multiemployer and Joint Trustee Pension PlansHydroelectric Relicensing
PacifiCorp contributesis a party to the PacifiCorp/IBEW Local 57 Retirement Trust Fund2016 amended Klamath Hydroelectric Settlement Agreement ("Local 57 Trust Fund"KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") (plan number 001)and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its subsidiary, Energy West Mining Company, previously contributedcustomers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to the UMWA 1974 Pension Plan (plan number 002). Contributions to these pension plans are based on the terms of collective bargaining agreements.
As a resultcontinue implementation of the Utah Mine DispositionKHSA. The agreement required the States, PacifiCorp and United Mine Workers of America ("UMWA") labor settlement, PacifiCorp's subsidiary, Energy West Mining Company, triggered involuntary withdrawalKRRC to file a new license transfer application to remove PacifiCorp from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing worklicense for the subsidiary. PacifiCorp recorded its estimateKlamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. In addition, the withdrawal obligation in December 2014 when withdrawal was considered probable and deferred the portionMOA provides for additional contingency funding of the obligation considered probable of recovery to a regulatory asset. PacifiCorp has subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees have determined a withdrawal liability of $115 million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a variety of factors, including the results of ongoing negotiations with the plan trustees.
The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from$45 million, equally split between PacifiCorp and the union.States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The Local 57 Trust Fund was established pursuantMOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the provisionsKRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the Taft-Hartley Act and although formedproperty transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending.
As of December 31, 2021, PacifiCorp's assets included $14 million of costs associated with the abilityKlamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for other employersPacifiCorp to participatemake certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $193 million over the next 10 years. Included in these estimates are commitments associated with the plan, there are no other employers that participate in this plan.KHSA.
Guarantees
The riskCompany has entered into guarantees as part of participating in multiemployer pension plans generally differs from single-employer plans in that assetsthe normal course of business and the sale of certain assets. These guarantees are pooled such that contributions by one employer may be usednot expected to provide benefits to employees of other participating employers and plan assets cannot revert back to employers. If an employer ceases participation in the plan, the employer may be obligated to payhave a withdrawal liability basedmaterial impact on the participants' unfunded, vested benefits in the plan. This occurred as a result of Company's consolidated financial results.
(17) Revenue from Contracts with Customers
Energy West Mining Company's withdrawal from the UMWA 1974 Pension Plan. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers, including any employers that withdrew during the three years prior to a mass withdrawal.Products and Services
The following table presents PacifiCorp's participation in individually significant joint trusteesummarizes the Company's energy products and multiemployer pension plans for the years ended December 31 (dollars in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | PPA zone status or | | | | | | | | | | | | |
| | | | plan funded status percentage for | | | | | | | | | | | | |
| | | | plan years beginning July 1, | | | | | | Contributions(1) | | |
Plan name | | Employer Identification Number | | 2018 | | 2017 | | 2016 | | Funding improvement plan | | Surcharge imposed under PPA(1) | | 2018 | | 2017 | | 2016 | | Year contributions to plan exceeded more than 5% of total contributions(2) |
Local 57 Trust Fund | | 87-0640888 | | At least 80% | | At least 80% | | At least 80% | | None | | None | | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | 2016, 2015, 2014 |
| |
(1) | PacifiCorp's minimum contributions to the plan are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreements, subject to ERISA minimum funding requirements. |
| |
(2) | For the Local 57 Trust Fund, information is for plan years beginning July 1, 2016, 2015 and 2014. Information for the plan year beginning July 1, 2017 is not yet available. |
The current collective bargaining agreements governing the Local 57 Trust Fund expire in 2023.
Defined Contribution Plan
PacifiCorp's 401(k) plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's levelservices Customer Revenue by regulated energy and nonregulated energy, with further disaggregation of contribution and, asregulated energy by line of January 1, 2018, all participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributionsbusiness, including a reconciliation to the 401(k) plan were $39 million, $39 million and $34 million for the years ended December 31, 2018, 2017 and 2016, respectively.
(10)Asset Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than thoseCompany's reportable segment information included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $994 million and $955 million as of December 31, 2018 and 2017, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilitiesNote 22, for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,847 | | | $ | 2,128 | | | $ | 2,828 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 9,801 | |
Retail Gas | | — | | | 859 | | | 115 | | | — | | | — | | | — | | | — | | | — | | | 974 | |
Wholesale | | 157 | | | 454 | | | 62 | | | — | | | 57 | | | — | | | — | | | (3) | | | 727 | |
Transmission and distribution | | 143 | | | 58 | | | 74 | | | 1,023 | | | — | | | 702 | | | — | | | — | | | 2,000 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 2,404 | | | — | | | — | | | (131) | | | 2,273 | |
Other | | 108 | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | 1 | | | 109 | |
Total Regulated | | 5,255 | | | 3,499 | | | 3,080 | | | 1,023 | | | 2,460 | | | 702 | | | — | | | (135) | | | 15,884 | |
Nonregulated | | — | | | 15 | | | 3 | | | 43 | | | 956 | | | 35 | | | 796 | | | 576 | | | 2,424 | |
Total Customer Revenue | | 5,255 | | | 3,514 | | | 3,083 | | | 1,066 | | | 3,416 | | | 737 | | | 796 | | | 441 | | | 18,308 | |
Other revenue | | 41 | | | 33 | | | 24 | | | 122 | | | 128 | | | (6) | | | 185 | | | 100 | | | 627 | |
Total | | $ | 5,296 | | | $ | 3,547 | | | $ | 3,107 | | | $ | 1,188 | | | $ | 3,544 | | | $ | 731 | | | $ | 981 | | | $ | 541 | | | $ | 18,935 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 215 |
| | $ | 215 |
|
Change in estimated costs | 9 |
| | (8 | ) |
Additions | — |
| | 6 |
|
Retirements | (5 | ) | | (6 | ) |
Accretion | 8 |
| | 8 |
|
Ending balance | $ | 227 |
| | $ | 215 |
|
| | | |
Reflected as: | | | |
Other current liabilities | $ | 21 |
| | $ | 25 |
|
Other long-term liabilities | 206 |
| | 190 |
|
| $ | 227 |
| | $ | 215 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,932 | | | $ | 1,924 | | | $ | 2,566 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 9,421 | |
Retail Gas | | — | | | 505 | | | 114 | | | — | | | — | | | — | | | — | | | — | | | 619 | |
Wholesale | | 107 | | | 199 | | | 45 | | | — | | | 17 | | | — | | | — | | | (2) | | | 366 | |
Transmission and distribution | | 96 | | | 60 | | | 95 | | | 887 | | | — | | | 641 | | | — | | | — | | | 1,779 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 1,397 | | | — | | | — | | | (139) | | | 1,258 | |
Other | | 108 | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | 110 | |
Total Regulated | | 5,243 | | | 2,688 | | | 2,822 | | | 887 | | | 1,414 | | | 641 | | | — | | | (142) | | | 13,553 | |
Nonregulated | | — | | | 16 | | | 2 | | | 26 | | | 134 | | | 18 | | | 817 | | | 515 | | | 1,528 | |
Total Customer Revenue | | 5,243 | | | 2,704 | | | 2,824 | | | 913 | | | 1,548 | | | 659 | | | 817 | | | 373 | | | 15,081 | |
Other revenue | | 98 | | | 24 | | | 30 | | | 109 | | | 30 | | | — | | | 119 | | | 65 | | | 475 | |
Total | | $ | 5,341 | | | $ | 2,728 | | | $ | 2,854 | | | $ | 1,022 | | | $ | 1,578 | | | $ | 659 | | | $ | 936 | | | $ | 438 | | | $ | 15,556 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,789 | | | $ | 1,938 | | | $ | 2,740 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 9,465 | |
Retail Gas | | — | | | 570 | | | 116 | | | — | | | — | | | — | | | — | | | — | | | 686 | |
Wholesale | | 99 | | | 309 | | | 51 | | | — | | | — | | | — | | | — | | | (2) | | | 457 | |
Transmission and distribution | | 98 | | | 57 | | | 98 | | | 876 | | | — | | | 690 | | | — | | | — | | | 1,819 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 1,122 | | | — | | | — | | | (118) | | | 1,004 | |
Other | | — | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | 2 | |
Total Regulated | | 4,986 | | | 2,874 | | | 3,007 | | | 876 | | | 1,122 | | | 690 | | | — | | | (122) | | | 13,433 | |
Nonregulated | | — | | | 30 | | | — | | | 36 | | | — | | | 17 | | | 744 | | | 577 | | | 1,404 | |
Total Customer Revenue | | 4,986 | | | 2,904 | | | 3,007 | | | 912 | | | 1,122 | | | 707 | | | 744 | | | 455 | | | 14,837 | |
Other revenue | | 82 | | | 23 | | | 30 | | | 101 | | | 9 | | | — | | | 188 | | | 101 | | | 534 | |
Total | | $ | 5,068 | | | $ | 2,927 | | | $ | 3,037 | | | $ | 1,013 | | | $ | 1,131 | | | $ | 707 | | | $ | 932 | | | $ | 556 | | | $ | 15,371 | |
(1)The BHE and Other reportable segment represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| HomeServices |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Brokerage | $ | 5,498 | | | $ | 4,520 | | | $ | 4,028 | |
Franchise | 85 | | | 76 | | | 68 | |
Total Customer Revenue | 5,583 | | | 4,596 | | | 4,096 | |
Mortgage and other revenue | 632 | | | 800 | | | 377 | |
Total | $ | 6,215 | | | $ | 5,396 | | | $ | 4,473 | |
Remaining Performance Obligations
The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2021, by reportable segment (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
BHE Pipeline Group | $ | 2,607 | | | $ | 21,038 | | | $ | 23,645 | |
| | | | | |
| | | | | |
(18)BHE Shareholders' Equity
Preferred Stock
As of December 31, 2021 and 2020, BHE had 1,649,988 and 3,750,000 shares outstanding of its Perpetual Preferred Stock (the "4% Perpetual Preferred Stock") issued to certain subsidiaries of Berkshire Hathaway Inc. The 4% Perpetual Preferred Stock has a liquidation preference of $1,000 per share and currently pays a 4.00% dividend per share on the liquidation preference. Dividends shall accrue and accumulate daily, be cumulative, compound semi-annually and, if declared, be payable in cash semi-annually in arrears on May 15 and November 15 of each year. If dividends are not declared and paid, any accumulating dividends shall continue to accumulate and compound. BHE may not make any dividends on shares of any other class or series of its capital stock (other than for dividends on shares of common stock payable in shares of common stock, unless the holders of the then outstanding 4% Perpetual Preferred Stock shall first receive, or simultaneously receive, a dividend in an amount at least equivalent to the amount accumulated and not previously paid. BHE may not declare or pay any dividends on shares of the 4% Perpetual Preferred Stock if such declaration or payment would constitute an event of default on BHE's senior indebtedness (as defined). BHE may, at its option, redeem the 4% Perpetual Preferred Stock in whole or in part at any time at a price per share equal to the liquidation preference.
Common Stock
On March 14, 2000, and as amended on December 7, 2005, BHE's shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares to BHE at the then-current fair value dependent on certain circumstances controlled by BHE.
Restricted Net Assets
BHE has maximum debt-to-total capitalization percentage restrictions imposed by its senior unsecured credit facilities expiring in June 2024 which, in certain circumstances, limit BHE's ability to make cash dividends or distributions. As a result of this restriction, BHE has restricted net assets of $18.3 billion as of December 31, 2021.
Certain of PacifiCorp's decommissioningBHE's subsidiaries have restrictions on their ability to dividend, loan or advance funds to BHE due to specific legal or regulatory restrictions, including, but not limited to, maximum debt-to-total capitalization percentages and reclamationcommitments made to state commissions. As a result of these restrictions, BHE's subsidiaries had restricted net assets of $20.3 billion as of December 31, 2021.
(19)Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Unrecognized | | Foreign | | | | Unrealized | | | | AOCI |
| | Amounts on | | Currency | | | | Gains (Losses) | | | | Attributable |
| | Retirement | | Translation | | | | on Cash Flow | | Noncontrolling | | To BHE |
| | Benefits | | Adjustment | | | | Hedges | | Interests | | Shareholders, Net |
| | | | | | | | | | | | |
Balance, December 31, 2018 | | $ | (358) | | | $ | (1,623) | | | | | $ | 36 | | | $ | — | | | $ | (1,945) | |
Other comprehensive (loss) income | | (59) | | | 327 | | | | | (29) | | | — | | | 239 | |
Balance, December 31, 2019 | | (417) | | | (1,296) | | | | | 7 | | | — | | | (1,706) | |
Other comprehensive (loss) income | | (65) | | | 234 | | | | | (15) | | | — | | | 154 | |
BHE GT&S acquisition | | (10) | | | — | | | | | — | | | 10 | | | — | |
Balance, December 31, 2020 | | (492) | | | (1,062) | | | | | (8) | | | 10 | | | (1,552) | |
Other comprehensive income (loss) | | 174 | | | (24) | | | | | 67 | | | (5) | | | 212 | |
Balance, December 31, 2021 | | $ | (318) | | | $ | (1,086) | | | | | $ | 59 | | | $ | 5 | | | $ | (1,340) | |
Reclassifications from AOCI to net income for the years ended December 31, 2021, 2020 and 2019 were insignificant. Additionally, refer to the "Foreign Operations" discussion in Note 13 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.
(20)Variable Interest Entities and Noncontrolling Interests
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As part of the GT&S Transaction, BHE acquired an indirect 25% economic interest in Cove Point, consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. BHE is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Included in noncontrolling interests on the Consolidated Balance Sheets are (i) Dominion Energy's 50% interest in Cove Point and Brookfield Super-Core Infrastructure Partner's 25% interest in Cove Point and (ii) preferred securities of subsidiaries of $58 million as of December 31, 2021 and 2020, consisting of $56 million of 8.061% cumulative preferred securities of Northern Electric plc, a subsidiary of Northern Powergrid, which are redeemable in the event of the revocation of Northern Electric plc's electricity distribution license by the Secretary of State, and $2 million of nonredeemable preferred stock of PacifiCorp.
(21)Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 1,096 | | | $ | 1,290 | |
Restricted cash and cash equivalents | 127 | | | 140 | |
Investments and restricted cash and cash equivalents and investments | 21 | | | 15 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 1,244 | | | $ | 1,445 | |
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 2,041 | | | $ | 1,855 | | | $ | 1,723 | |
Income taxes received, net(1) | $ | 1,309 | | | $ | 1,361 | | | $ | 850 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 834 | | | $ | 801 | | | $ | 888 | |
| | | | | |
(1)Includes $1,441 million, $1,504 million and $942 million of income taxes received from Berkshire Hathaway in 2021, 2020 and 2019, respectively.
(22)Segment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
PacifiCorp | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
MidAmerican Funding | 3,547 | | | 2,728 | | | 2,927 | |
NV Energy | 3,107 | | | 2,854 | | | 3,037 | |
Northern Powergrid | 1,188 | | | 1,022 | | | 1,013 | |
BHE Pipeline Group | 3,544 | | | 1,578 | | | 1,131 | |
BHE Transmission | 731 | | | 659 | | | 707 | |
BHE Renewables | 981 | | | 936 | | | 932 | |
HomeServices | 6,215 | | | 5,396 | | | 4,473 | |
BHE and Other(1) | 541 | | | 438 | | | 556 | |
Total operating revenue | $ | 25,150 | | | $ | 20,952 | | | $ | 19,844 | |
| | | | | |
Depreciation and amortization: | | | | | |
PacifiCorp | $ | 1,088 | | | $ | 1,209 | | | $ | 954 | |
MidAmerican Funding | 914 | | | 716 | | | 638 | |
NV Energy | 549 | | | 502 | | | 482 | |
Northern Powergrid | 305 | | | 266 | | | 254 | |
BHE Pipeline Group | 492 | | | 231 | | | 115 | |
BHE Transmission | 238 | | | 201 | | | 240 | |
BHE Renewables | 241 | | | 284 | | | 282 | |
HomeServices | 52 | | | 45 | | | 47 | |
BHE and Other(1) | 2 | | | 1 | | | (1) | |
Total depreciation and amortization | $ | 3,881 | | | $ | 3,455 | | | $ | 3,011 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating income: | | | | | |
PacifiCorp | $ | 1,133 | | | $ | 924 | | | $ | 1,072 | |
MidAmerican Funding | 416 | | | 454 | | | 549 | |
NV Energy | 621 | | | 649 | | | 655 | |
Northern Powergrid | 543 | | | 421 | | | 472 | |
BHE Pipeline Group | 1,516 | | | 779 | | | 572 | |
BHE Transmission | 339 | | | 316 | | | 323 | |
BHE Renewables | 329 | | | 291 | | | 336 | |
HomeServices | 505 | | | 511 | | | 222 | |
BHE and Other(1) | (75) | | | (54) | | | (51) | |
Total operating income | 5,327 | | | 4,291 | | | 4,150 | |
Interest expense | (2,118) | | | (2,021) | | | (1,912) | |
Capitalized interest | 64 | | | 80 | | | 77 | |
Allowance for equity funds | 126 | | | 165 | | | 173 | |
Interest and dividend income | 89 | | | 71 | | | 117 | |
Gains (losses) on marketable securities, net | 1,823 | | | 4,797 | | | (288) | |
Other, net | (17) | | | 88 | | | 97 | |
Total income before income tax (benefit) expense and equity loss | $ | 5,294 | | | $ | 7,471 | | | $ | 2,414 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| |
| | | | | |
Interest expense: | | | | | |
PacifiCorp | $ | 430 | | | $ | 426 | | | $ | 401 | |
MidAmerican Funding | 319 | | | 322 | | | 302 | |
NV Energy | 206 | | | 227 | | | 229 | |
Northern Powergrid | 130 | | | 130 | | | 139 | |
BHE Pipeline Group | 143 | | | 74 | | | 52 | |
BHE Transmission | 155 | | | 148 | | | 157 | |
BHE Renewables | 158 | | | 166 | | | 174 | |
HomeServices | 4 | | | 11 | | | 25 | |
BHE and Other(1) | 573 | | | 517 | | | 433 | |
Total interest expense | $ | 2,118 | | | $ | 2,021 | | | $ | 1,912 | |
| | | | | |
Income tax (benefit) expense: | | | | | |
PacifiCorp | $ | (78) | | | $ | (75) | | | $ | 61 | |
MidAmerican Funding | (680) | | | (574) | | | (377) | |
NV Energy | 56 | | | 61 | | | 98 | |
Northern Powergrid | 192 | | | 96 | | | 59 | |
BHE Pipeline Group | 269 | | | 162 | | | 138 | |
BHE Transmission | 10 | | | 13 | | | 11 | |
BHE Renewables(2) | (753) | | | (602) | | | (325) | |
HomeServices | 138 | | | 138 | | | 51 | |
BHE and Other(1) | (286) | | | 1,089 | | | (314) | |
Total income tax (benefit) expense | $ | (1,132) | | | $ | 308 | | | $ | (598) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Earnings on common shares: | | | | | |
PacifiCorp | $ | 889 | | | $ | 741 | | | $ | 773 | |
MidAmerican Funding | 883 | | | 818 | | | 781 | |
NV Energy | 439 | | | 410 | | | 365 | |
Northern Powergrid | 247 | | | 201 | | | 256 | |
BHE Pipeline Group | 807 | | | 528 | | | 422 | |
BHE Transmission | 247 | | | 231 | | | 229 | |
BHE Renewables(2) | 451 | | | 521 | | | 431 | |
HomeServices | 387 | | | 375 | | | 160 | |
BHE and Other(1) | 1,319 | | | 3,092 | | | (467) | |
Total earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | 2,950 | |
| | | | | |
Capital expenditures: | | | | | |
PacifiCorp | $ | 1,513 | | | $ | 2,540 | | | $ | 2,175 | |
MidAmerican Funding | 1,912 | | | 1,836 | | | 2,810 | |
NV Energy | 749 | | | 675 | | | 657 | |
Northern Powergrid | 742 | | | 682 | | | 602 | |
BHE Pipeline Group | 1,128 | | | 659 | | | 687 | |
BHE Transmission | 279 | | | 372 | | | 247 | |
BHE Renewables | 225 | | | 95 | | | 122 | |
HomeServices | 42 | | | 36 | | | 54 | |
BHE and Other | 21 | | | (130) | | | 10 | |
Total capital expenditures | $ | 6,611 | | | $ | 6,765 | | | $ | 7,364 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Property, plant and equipment, net: | | | | | |
PacifiCorp | $ | 22,914 | | | $ | 22,430 | | | $ | 20,973 | |
MidAmerican Funding | 20,302 | | | 19,279 | | | 18,377 | |
NV Energy | 10,231 | | | 9,865 | | | 9,613 | |
Northern Powergrid | 7,572 | | | 7,230 | | | 6,606 | |
BHE Pipeline Group | 15,692 | | | 15,097 | | | 5,482 | |
BHE Transmission | 6,590 | | | 6,445 | | | 6,157 | |
BHE Renewables | 6,103 | | | 5,645 | | | 5,976 | |
HomeServices | 169 | | | 159 | | | 161 | |
BHE and Other | 243 | | | (22) | | | (40) | |
Total property, plant and equipment, net | $ | 89,816 | | | $ | 86,128 | | | $ | 73,305 | |
| | | | | |
Total assets: | | | | | |
PacifiCorp | $ | 27,615 | | | $ | 26,862 | | | $ | 24,861 | |
MidAmerican Funding | 25,352 | | | 23,530 | | | 22,664 | |
NV Energy | 15,239 | | | 14,501 | | | 14,128 | |
Northern Powergrid | 9,326 | | | 8,782 | | | 8,385 | |
BHE Pipeline Group | 20,434 | | | 19,541 | | | 6,100 | |
BHE Transmission | 9,476 | | | 9,208 | | | 8,776 | |
BHE Renewables | 11,829 | | | 12,004 | | | 9,961 | |
HomeServices | 4,574 | | | 4,955 | | | 3,846 | |
BHE and Other | 8,220 | | | 7,933 | | | 1,330 | |
Total assets | $ | 132,065 | | | $ | 127,316 | | | $ | 100,051 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue by country: | | | | | |
United States | $ | 23,215 | | | $ | 19,254 | | | $ | 18,108 | |
United Kingdom | 1,188 | | | 1,022 | | | 1,011 | |
Canada | 719 | | | 653 | | | 706 | |
Other | 28 | | | 23 | | | 19 | |
Total operating revenue by country | $ | 25,150 | | | $ | 20,952 | | | $ | 19,844 | |
| | | | | |
Income before income tax (benefit) expense and equity loss by country: | | | | |
United States | $ | 4,650 | | | $ | 6,954 | | | $ | 1,866 | |
United Kingdom | 454 | | | 338 | | | 326 | |
Canada | 181 | | | 173 | | | 178 | |
Other | 9 | | | 6 | | | 44 | |
Total income before income tax (benefit) expense and equity loss by country: | $ | 5,294 | | | $ | 7,471 | | | $ | 2,414 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Property, plant and equipment, net by country: | | | | | |
United States | $ | 75,774 | | | $ | 72,583 | | | $ | 60,634 | |
United Kingdom | 7,487 | | | 7,134 | | | 6,504 | |
Canada | 6,547 | | | 6,401 | | | 6,157 | |
Other | 8 | | | 10 | | | 10 | |
Total property, plant and equipment, net by country | $ | 89,816 | | | $ | 86,128 | | | $ | 73,305 | |
(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate to jointly ownedother corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
(2)Income tax (benefit) expense includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2021 and 2020 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE | | | | | | | | | | |
| | | MidAmerican | | NV | | Northern | | Pipeline | | BHE | | BHE | | | | | | |
| PacifiCorp | | Funding | | Energy | | Powergrid | | Group | | Transmission | | Renewables | | HomeServices | | | | Total |
| | | | | | | | | | | | | | | | | | | |
December 31, 2019 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 978 | | | $ | 73 | | | $ | 1,520 | | | $ | 95 | | | $ | 1,456 | | | | | $ | 9,722 | |
Acquisitions | — | | | — | | | — | | | — | | | 1,730 | | | — | | | — | | | 1 | | | | | 1,731 | |
Foreign currency translation | — | | | — | | | — | | | 22 | | | — | | | 31 | | | — | | | — | | | | | 53 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
December 31, 2020 | 1,129 | | | 2,102 | | | 2,369 | | | 1,000 | | | 1,803 | | | 1,551 | | | 95 | | | 1,457 | | | | | 11,506 | |
Acquisitions | — | | | — | | | — | | | — | | | 11 | | | — | | | — | | | 129 | | | | | 140 | |
Foreign currency translation | — | | | — | | | — | | | (8) | | | — | | | 12 | | | — | | | — | | | | | 4 | |
| | | | | | | | | | | | | | | | | | | |
December 31, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 992 | | | $ | 1,814 | | | $ | 1,563 | | | $ | 95 | | | $ | 1,586 | | | | | $ | 11,650 | |
PacifiCorp and its subsidiaries
Consolidated Financial Section
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with PacifiCorp's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2021, was $888 million, an increase of $149 million, or 20%, compared to 2020, primarily due to higher utility gross margin (excluding $231 million of decreases fully offset in depreciation, operating, other income/expense and income tax expense due to prior year regulatory adjustments); lower operations and maintenance expense primarily due to prior year costs associated with the 2020 Wildfires and changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met; and favorable income tax expense from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking; partially offset by higher depreciation and amortization expense (excluding $376 million of decreases offset in operating revenue and income tax expense due to prior year regulatory adjustments) from the impacts of the depreciation study for which rates became effective January 2021 and higher plant in-service; and lower allowances for equity and borrowed funds used during construction. Utility margin increased $145 million (excluding the $231 million of fully offsetting decreases) primarily due to the higher retail, wheeling and wholesale revenue; higher deferred net power costs; and lower purchased electricity volumes; partially offset by higher purchased electricity prices; and higher natural gas- and coal-fueled generation costs. Retail customer volumes increased 3.1% due to increase in customer usage, increase in the average number of customers and favorable impacts of weather. Energy generated increased 10% for 2021 compared to 2020 primarily due higher wind-powered, natural gas-fueled and coal-fueled generation, partially offset by lower hydroelectric-powered generation. Wholesale electricity sales volumes decreased 3% and purchased electricity volumes decreased 17%.
Net income for the year ended December 31, 2020 was $739 million, a decrease of $32 million, or 4%, compared to 2019, primarily due to costs associated with the 2020 Wildfires and the Klamath Hydroelectric Project of $169 million; higher net interest expense of $36 million from higher long-term debt and lower cash balances; higher pension and other postretirement costs of $13 million; and higher property taxes of $10 million; partially offset by lower income tax expense of $99 million (excluding $37 million fully offset primarily in depreciation expense) primarily driven by higher PTCs substantially due to repowered wind-powered generating facilities and lower pre-tax income; higher utility margin of $47 million (excluding $231 million of increases fully offset in depreciation, operating, other income/expense and income tax expense as a result of regulatory adjustments as ordered by the UPSC, the OPUC and the IPUC); higher allowances for equity and borrowed funds used during construction of $38 million; and prior year costs associated with the early retirement of a coal-fueled generation unit totaling $24 million. Utility margin increased primarily due to lower coal-fueled generation volumes, lower purchased electricity prices, higher average retail rates and lower natural gas-fueled generation costs, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower retail customer volumes and higher purchased electricity volumes. Retail customer volumes decreased 1.4% primarily due to impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of residential and commercial customers and the favorable impact of weather. Energy generated decreased 4% for 2020 compared to 2019 primarily due to lower coal-fueled generation, partially offset by higher wind and hydroelectric-powered generation. Wholesale electricity sales volumes decreased 4% and purchased electricity volumes increased 9%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
PacifiCorp's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in PacifiCorp's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin: | | | | | | | | | | | | | |
Operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | 5 | % |
Cost of fuel and energy | 1,831 | | | 1,790 | | | 41 | | 2 | | | 1,790 | | | 1,795 | | | (5) | | — | |
Utility margin | 3,465 | | | 3,551 | | | (86) | | (2) | | | 3,551 | | | 3,273 | | | 278 | | 8 | |
Operations and maintenance | 1,031 | | | 1,209 | | | (178) | | (15) | | | 1,209 | | | 1,048 | | | 161 | | 15 | |
Depreciation and amortization | 1,088 | | | 1,209 | | | (121) | | (10) | | | 1,209 | | | 954 | | | 255 | | 27 | |
Property and other taxes | 213 | | | 209 | | | 4 | | 2 | | | 209 | | | 199 | | | 10 | | 5 | |
Operating income | $ | 1,133 | | | $ | 924 | | | $ | 209 | | 23 | % | | $ | 924 | | | $ | 1,072 | | | $ | (148) | | (14) | % |
Utility Margin
A comparison of key operating results related to utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
| | | | | | | | | | | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | | | |
Operating revenue | | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | | 5 | % |
Cost of fuel and energy | | 1,831 | | | 1,790 | | | 41 | | | 2 | | | 1,790 | | | 1,795 | | | (5) | | | — | |
Utility margin | | $ | 3,465 | | | $ | 3,551 | | | $ | (86) | | | (2) | % | | $ | 3,551 | | | $ | 3,273 | | | $ | 278 | | | 8 | % |
| | | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | | |
Residential | | 17,905 | | | 17,150 | | | 755 | | | 4 | % | | 17,150 | | | 16,668 | | | 482 | | | 3 | % |
Commercial(1) | | 18,839 | | | 17,727 | | | 1,112 | | | 6 | | | 17,727 | | | 18,151 | | | (424) | | | (2) | |
Industrial(1) | | 17,909 | | | 18,039 | | | (130) | | | (1) | | | 18,039 | | | 19,049 | | | (1,010) | | | (5) | |
Other(1) | | 1,621 | | | 1,644 | | | (23) | | | (1) | | | 1,644 | | | 1,475 | | | 169 | | | 11 | |
Total retail | | 56,274 | | | 54,560 | | | 1,714 | | | 3 | | | 54,560 | | | 55,343 | | | (783) | | | (1) | |
Wholesale | | 5,113 | | | 5,249 | | | (136) | | | (3) | | | 5,249 | | | 5,480 | | | (231) | | | (4) | |
Total sales | | 61,387 | | | 59,809 | | | 1,578 | | | 3 | % | | 59,809 | | | 60,823 | | | (1,014) | | | (2) | % |
| | | | | | | | | | | | | | | | |
Average number of retail customers | | | | | | | | | | | | | | | | |
(in thousands) | | 2,003 | | | 1,967 | | | 36 | | | 2 | % | | 1,967 | | | 1,933 | | | 34 | | | 2 | % |
| | | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | | |
Retail | | $ | 86.08 | | | $ | 90.59 | | | $ | (4.51) | | | (5) | % | | $ | 90.59 | | | $ | 84.80 | | | $ | 5.79 | | | 7 | % |
Wholesale | | $ | 37.90 | | | $ | 35.56 | | | $ | 2.34 | | | 7 | % | | $ | 35.56 | | | $ | 35.21 | | | $ | 0.35 | | | 1 | % |
| | | | | | | | | | | | | | | | |
Heating degree days | | 9,914 | | | 10,155 | | | (241) | | | (2) | % | | 10,155 | | | 11,143 | | | (988) | | | (9) | % |
Cooling degree days | | 2,431 | | | 2,111 | | | 320 | | | 15 | % | | 2,111 | | | 1,773 | | | 338 | | | 19 | % |
| | | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | | |
Coal | | 31,566 | | | 30,636 | | | 930 | | | 3 | % | | 30,636 | | | 34,510 | | | (3,874) | | | (11) | % |
Natural gas | | 13,323 | | | 12,045 | | | 1,278 | | | 11 | | | 12,045 | | | 12,058 | | | (13) | | | — | |
Wind(2) | | 6,686 | | | 3,769 | | | 2,917 | | | 77 | | | 3,769 | | | 2,266 | | | 1,503 | | | 66 | |
Hydroelectric and other(2) | | 3,010 | | | 3,223 | | | (213) | | | (7) | | | 3,223 | | | 2,961 | | | 262 | | | 9 | |
Total energy generated | | 54,585 | | | 49,673 | | | 4,912 | | | 10 | | | 49,673 | | | 51,795 | | | (2,122) | | | (4) | |
Energy purchased | | 11,601 | | | 14,054 | | | (2,453) | | | (17) | | | 14,054 | | | 12,906 | | | 1,148 | | | 9 | |
Total | | 66,186 | | | 63,727 | | | 2,459 | | | 4 | % | | 63,727 | | | 64,701 | | | (974) | | | (2) | % |
| | | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | | |
Energy generated(3) | | $ | 18.05 | | | $ | 18.74 | | | $ | (0.69) | | | (4) | % | | $ | 18.74 | | | $ | 19.36 | | | $ | (0.62) | | | (3) | % |
Energy purchased | | $ | 66.93 | | | $ | 47.60 | | | $ | 19.33 | | | 41 | % | | $ | 47.60 | | | $ | 54.20 | | | $ | (6.60) | | | (12) | % |
(1) GWh amounts are net of energy used by the related generating facilities.
(2)All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Utility margin decreased $86 million (including the $231 million of fully offsetting decreases) for 2021 compared to 2020 primarily due to:
•$111 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;
•$99 million of lower retail revenue primarily due to $234 million fully offset in depreciation expense, income tax expense, fuel expense, and other income (expense) due to accelerated depreciation of certain coal-fueled units in Utah and Oregon and recognition of certain Utah regulatory balances in the prior year, and lower average retail prices, partially offset by higher retail customer volumes. Retail customer volumes increased 3.1% due to an increase in residential and commercial customer usage, increase in the average number of customers and favorable impacts of weather, primarily in Oregon, Washington and Idaho;
•$88 million of higher natural gas-fueled generation costs primarily due to higher average prices and higher volumes; and
•$34 million of lower other revenue due to prior year recognition of prior OATT revenue related deferrals in Oregon used to accelerate the depreciation of certain retired wind equipment as a result of the 2020 Oregon RAC settlement (offset in depreciation expense).
The decreases above were partially offset by:
•$141 million primarily from higher deferred net power costs in accordance with established adjustment mechanisms;
•$43 million of favorable wheeling activities;
•$33 million of lower coal-fueled generation costs primarily due to $37 million of accelerated recognition of certain Utah regulatory balances associated with the 2015 Utah mine sites. PacifiCorp is committeddisposition and certain Cholla Unit 4 related closure costs in Oregon and Idaho (offset in income tax expense) in the prior year and lower prices, partially offset by higher volumes;
•$19 million of higher other revenue primarily due to payhigher REC, fly ash and by-product revenues; and
•$7 million of higher wholesale revenue due to higher average wholesale market prices, partially offset by lower wholesale volumes.
Operations and maintenance decreased $178 million, or 15%, for 2021 compared to 2020 primarily due to prior year estimated losses associated with the 2020 Wildfires of $136 million, net of expected insurance recoveries, changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met, lower thermal plant maintenance expense and lower labor expenses, partially offset by higher wind plant and distribution maintenance and higher legal and insurance expenses associated with the 2020 Wildfires.
Depreciation and amortization decreased $121 million, or 10%, for 2021 compared to 2020 primarily due to prior year accelerated depreciation of $376 million as a proportionateresult of regulatory adjustments ordered by the UPSC, the OPUC and the IPUC (fully offset in retail revenue, other revenue, and income tax expense), including accelerated depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment as a result the 2020 Oregon RAC settlement, partially offset by the impacts of the depreciation study for which rates became effective January 1, 2021 of approximately $158 million and higher plant in-service balances.
Property and other taxes increased $4 million, or 2%, for 2021 compared to 2020 primarily due to higher property taxes in Oregon and Wyoming, partially offset by lower property taxes in Utah and Washington.
Interest expense increased $4 million, or 1%, for 2021 compared to 2020 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds decreased $72 million, or 49%, for 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.
Interest and dividend income increased$14 million, or 140%, for 2021 compared to 2020 primarily due to higher carrying charges on DSM regulatory assets in the current year.
Income tax benefit increased $4 million, or 5%, for 2021 compared to 2020. The effective tax rate was (10)% and (11)% for 2021 and 2020, respectively. The effective tax rate increased primarily as a result of lower effects of ratemaking associated with excess deferred income tax amortization, offset by increased PTCs from PacifiCorp's new wind-powered generating facilities in the current year. In 2020, $118 million of excess deferred income taxes was amortized pursuant to regulatory orders from Utah, Oregon and Idaho, whereby portions of excess deferred income taxes were used to accelerate depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment or offset other regulatory balances for these jurisdictions.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Utility margin increased $278 million for 2020 compared to 2019 primarily due to:
•$249 million increase in retail revenue, including $234 million fully offset in depreciation expense and income tax expense due to accelerated depreciation of certain coal-fueled units in Utah and Oregon and recognition of certain Utah regulatory balances and higher average retail prices, partially offset by lower retail customer volumes. Retail customer volumes decreased 1.4% primarily due to impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of residential and commercial customers and the favorable impact of weather;
•$49 million of lower coal-fueled generation costs primarily due to lower volumes of $78 million, partially offset by $37 million of accelerated recognition of certain Utah regulatory balances associated with the 2015 Utah mine disposition and certain Cholla Unit 4 related closure costs in Oregon and Idaho (offset in income tax expense) and higher prices of $9 million;
•$34 million of higher other revenue due to recognition of prior OATT revenue related deferrals in Oregon used to accelerate the depreciation of certain retired wind equipment as a result of the 2020 Oregon RAC settlement (offset in depreciation expense);
•$31 million of lower purchased electricity costs, primarily due to lower average market prices, partially offset by higher volumes; and
•$24 million of lower natural gas-fueled generation costs primarily due to lower average prices and lower volumes.
The increases above were partially offset by:
•$106 million primarily from lower deferrals and higher amortization of previous deferrals of incurred net power costs in accordance with established adjustment mechanisms.
Operations and maintenance increased $161 million, or 15%, for 2020 compared to 2019 primarily due to costs associated with the 2020 Wildfires of $136 million, net of expected insurance recoveries, and costs associated with the Klamath Hydroelectric Project of $33 million, higher vegetation management and wildfire mitigation costs of $26 million and increased bad debt expense of $5 million, partially offset by prior year costs associated with the early retirement of Cholla Unit 4 of $24 million and lower employee related expenses of $7 million as a result of COVID-19.
Depreciation and amortization increased $255 million, or 27%, for 2020 compared to 2019 primarily due to current year accelerated depreciation of $376 million as a result of regulatory adjustments ordered by the UPSC, the OPUC and the IPUC (fully offset in retail revenue, other revenue, and income tax expense), including accelerated depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment as a result the 2020 Oregon RAC settlement, partially offset by prior year accelerated depreciation of $120 million (offset in income tax expense) on Oregon's share of certain retired wind equipment due to repowering as a result of the 2019 Oregon RAC settlement.
Property and other taxes increased $10 million, or 5%, for 2020 compared to 2019 primarily due to higher property taxes in Oregon and Utah.
Interest expense increased $25 million, or 6%, for 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds increased $38 million, or 35%, for 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income decreased $11 million, or 52%, for 2020 compared to 2019 primarily due to lower average interest rates in the current year.
Other, net decreased $22 million, or 69% for 2020 compared to 2019 primarily due to higher pension and post retirement costs of $13 million and costs associated with the recognition of Utah's share of the decommissioningpost retirement settlement loss associated with the 2015 Utah mine disposition (offset in income tax expense).
Income tax (benefit) expense decreased $136 million to a benefit of $75 million for 2020 compared to an expense of $61 million for 2019. The effective tax rate was (11)% and 7% for 2020 and 2019, respectively. The effective tax rate decreased primarily as a result of higher amortization of excess deferred income taxes in 2020 and higher PTCs. In 2020, $118 million of excess deferred income taxes was amortized pursuant to regulatory orders from Utah, Oregon and Idaho, whereby portions of excess deferred income taxes were used to accelerate depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment or reclamation costs.offset other regulatory balances for these jurisdictions. In 2019, $91 million of Oregon's allocated excess deferred income taxes was amortized pursuant to the event2019 Oregon RAC proceeding, whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment due to repowering.
Liquidity and Capital Resources
As of December 31, 2021, PacifiCorp's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 179 | |
| | |
Credit facilities(1) | | 1,200 | |
Less: | | |
| | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | 982 | |
| | |
Total net liquidity | | $ | 1,161 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding PacifiCorp's credit facilities.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $1.8 billion and $1.6 billion, respectively. The increase is primarily due to higher cash received for income taxes and higher collections from retail customers, partially offset by higher wholesale purchases and timing of operating payables.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $1.6 billion and $1.5 billion, respectively. The increase is primarily due to lower purchased power prices, lower cash paid for income taxes and lower operating expense payments due to timing, partially offset by lower collections from wholesale and retail customers and higher fuel expense payments due to timing.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(1.5) billion and $(2.5) billion, respectively. The decrease in net cash outflows from investing activities is mainly due to a defaultdecrease in capital expenditures of $1.0 billion.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $(2.5) billion and $(2.2) billion, respectively. The increase in net cash outflows from investing activities is mainly due to an increase in capital expenditures of $365 million, partially offset by proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015.
Financing Activities
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31, 2021, PacifiCorp had no short-term debt outstanding. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%. For further discussion, refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Long-term Debt
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.
PacifiCorp made repayments on long-term debt totaling $870 million and $38 million during the years ended December 31, 2021 and 2020, respectively.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2021, PacifiCorp estimated it would be able to issue up to $11.8 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances are subject to market conditions and amounts are further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
Credit Facilities
In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.
In 2020, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations decreased by $38 million due to maturities.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.
Preferred Stock
As of December 31, 2021 and 2020, PacifiCorp had non-redeemable preferred stock outstanding with an aggregate stated value of $2 million.
Common Shareholder's Equity
In 2021 and 2020, PacifiCorp declared and paid dividends of $150 million and $— million, respectively, to PPW Holdings LLC.
Capitalization
PacifiCorp manages its capitalization and liquidity position to maintain a prudent capital structure with an objective of retaining strong investment grade credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, customers and creditors and provide a competitive cost of capital and predictable capital market access.
Under existing or prospective authoritative accounting guidance, such as guidance pertaining to consolidations and leases, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as lease obligations on PacifiCorp's financial statements. While PacifiCorp has successfully amended covenants in financing arrangements that may be impacted, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers under financing agreements and from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its indirect parent company, BHE, or take other actions.
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Wind generation | $ | 933 | | | $ | 1,277 | | | $ | 131 | | | $ | 210 | | | $ | 473 | | | $ | 440 | |
Electric distribution | 413 | | | 613 | | | 618 | | | 610 | | | 586 | | | 515 | |
Electric transmission | 612 | | | 405 | | | 315 | | | 927 | | | 1,617 | | | 836 | |
Other | 217 | | | 245 | | | 449 | | | 254 | | | 641 | | | 710 | |
Total | $ | 2,175 | | | $ | 2,540 | | | $ | 1,513 | | | $ | 2,001 | | | $ | 3,317 | | | $ | 2,501 | |
PacifiCorp's 2019 and 2021 IRPs identified a roadmap for a significant increase in renewable and carbon free generation resources, coal to natural gas conversion of certain coal-fueled units, energy storage and associated transmission. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
•Wind generation includes both growth projects and operating expenditures. Growth projects include:
◦Construction of wind-powered generating facilities at PacifiCorp totaled $107 million for 2021, $1,148 million for 2020 and $338 million for 2019. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $131 million in 2022, $405 million in 2023 and $373 million in 2024.
◦Repowering of existing wind-powered generating facilities at PacifiCorp totaled $9 million in 2021, $125 million in 2020 and $585 million in 2019. All existing wind-powered generating facilities at PacifiCorp have been repowered as of December 31, 2021.
◦The 2021 IRP also included PacifiCorp's planned acquisition and repowering of two wind-powered generating facilities. The repowered facilities are expected to be placed in-service in 2023 and 2024. PacifiCorp spent $11 million in 2021 and planned spending for acquiring and repowering generating facilities totals $60 million in 2022, $36 million in 2023 and $34 million in 2024.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $176 million in 2021, $187 million in 2020 and $4 million in 2019, and planned spending totals $153 million in 2022, $133 million in 2023 and $127 million in 2024. Remaining investments relate to expenditures for new connections and distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission investment in 2021 through 2024 primarily reflects planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. PacifiCorp is advancing permitting and regulatory approvals related to the projects. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $565 million in 2022, $1,143 million in 2023, and $437 million in 2024.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $108 million in 2021, $75 million in 2020 and $62 million for 2019. Planned information technology spending totals $167 million in 2022, $163 million in 2023 and $136 million in 2024. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
Off-Balance Sheet Arrangements
PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees or similar arrangements. PacifiCorp currently has indemnification obligations in connection with the sale or transfer of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with authoritative accounting guidance. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of thethese obligations is remote. Refer to Notes 11 and 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these obligations and arrangements.
Material Cash Requirements
PacifiCorp has cash requirements that may affect its consolidated financial condition that arise primarily from long-term debt (refer to Note 8), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), cost of removal and AROs (refer to Notes 6 and 11), construction and other joint participants, PacifiCorp may be obligateddevelopment costs (refer to absorb, directly or by paying additional sumsLiquidity and Capital Resources included within this Item 7). Refer to the entity, a proportionate sharerespective referenced note in Notes to Consolidated Financial Statements in Item 8 of the defaulting party's liability. PacifiCorp's estimated sharethis Form 10-K for additional information.
PacifiCorp has cash requirements relating to interest payments of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.$6.5 billion on long-term debt, including $400 million due in 2022.
(11)Risk Management and Hedging Activities
Regulatory Matters
PacifiCorp is exposedsubject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding PacifiCorp's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, PacifiCorp would have been required to post $218 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market fluctuationsprice volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.
Inflation
PacifiCorp operates under a cost-of-service based rate structure administered by various state commissions and the FERC. Under this rate structure, PacifiCorp is allowed to include prudent costs in its rates, including the impact of inflation. PacifiCorp seeks to minimize the potential impact of inflation on its operations through the use of energy and other cost adjustment clauses and tariff riders, by employing prudent risk management and hedging strategies and entering into contracts with fixed pricing where possible by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by PacifiCorp's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with PacifiCorp's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $1.4 billion and total regulatory liabilities were $2.8 billion as of December 31, 2021. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's regulatory assets and liabilities.
Pension and Other Postretirement Benefits
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans as described in Note 10. PacifiCorp recognizes the funded status of these defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2021, PacifiCorp recognized a net asset totaling $46 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2021, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets and accumulated other comprehensive loss totaled $260 million and $23 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rate and expected long-term rate of return on plan assets. These key assumptions are reviewed annually and modified as appropriate. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about PacifiCorp's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2021.
PacifiCorp chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date with cash flows aligning to the expected timing and amount of plan liabilities. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, PacifiCorp evaluates the investment allocation between return-seeking investment and fixed income securities based on the funded status of the plan and utilizes the asset allocation and return assumptions for each asset class based on forward-looking views of the financial markets and historical performance. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. PacifiCorp regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plan |
| +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | |
Effect on December 31, 2021 Benefit Obligations: | | | | | | | |
Discount rate | $ | (50) | | | $ | 55 | | | $ | (13) | | | $ | 15 | |
| | | | | | | |
Effect on 2021 Periodic Cost: | | | | | | | |
Discount rate | $ | — | | | $ | — | | | $ | 1 | | | $ | (1) | |
Expected rate of return on plan assets | (5) | | | 5 | | | (2) | | | 2 | |
A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and PacifiCorp's funding policy for each plan.
Income Taxes
In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on PacifiCorp's consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's income taxes.
It is probable that PacifiCorp will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers in certain state jurisdictions. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $1.3 billion and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $264 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
PacifiCorp's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. PacifiCorp's significant market risks are primarily associated with commodity prices, interest rates and interest rates. the extension of credit to counterparties with which PacifiCorp transacts. The following discussion addresses the significant market risks associated with PacifiCorp's business activities. PacifiCorp has established guidelines for credit risk management. Refer to Notes 2 and 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's contracts accounted for as derivatives.
PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp's exposure to market and credit risk, the risk management committee recommends, and executive management establishes, policies, limits and approved products, which are reviewed frequently to respond to changing market conditions.
Risk is an inherent part of PacifiCorp's business and activities. PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in PacifiCorp's business. The risk management policy governs energy transactions and is designed for hedging PacifiCorp's existing energy and asset exposures, and to a limited extent, the policy permits arbitrage and trading activities to take advantage of market inefficiencies. The policy also governs the types of transactions authorized for use and establishes guidelines for credit risk management and management information systems required to effectively monitor such transactions. PacifiCorp's risk management policy provides for the use of only those contracts that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions.
Commodity Price Risk
PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as itPacifiCorp has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report, each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. PacifiCorp's exposure to commodity price risk is generally limited by its ability to include commodity costs in rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
PacifiCorp measures, monitors and manages the market risk in its electricity and natural gas portfolio in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period. PacifiCorp has a risk management policy that requires increasing volumes of hedge transactions over a three-year position management and hedging horizon to reduce market risk of its electricity and natural gas portfolio.
PacifiCorp maintained compliance with its risk management policy and limit procedures during the year ended December 31, 2021.
The table that follows summarizes PacifiCorp's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $5 million and $24 million as of December 31, 2021 and 2020, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | 53 | | | $ | 104 | | | $ | 2 | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | (17) | | | $ | 5 | | | $ | (39) | |
PacifiCorp's commodity derivative contracts are generally recoverable from customers in rates; therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose PacifiCorp to earnings volatility. As of December 31, 2021 and 2020, a regulatory liability of $53 million and a regulatory asset of $17 million, respectively, was recorded related to the net derivative asset of $53 million and a net derivative liability of $17 million, respectively. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, natural gas or fuel are higher or the level of wholesale electricity sales are lower than what is included in rates, including the impacts of adjustment mechanisms.
Interest Rate Risk
PacifiCorp is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, PacifiCorp's fixed-rate long-term debt does not expose PacifiCorp to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity. PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge allThe nature and amount of its commodity pricePacifiCorp's short- and interest rate risks, thereby exposing the unhedged portionlong-term debt can be expected to changes invary from period to period as a result of future business requirements, market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives.conditions and other factors. Refer to Notes 27, 8 and 1213 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on derivative contracts.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair valuediscussion of PacifiCorp's derivative contracts, on a gross basis,short- and reconciles those amountslong-term debt.
As of December 31, 2021 and 2020, PacifiCorp had short- and long-term variable-rate obligations totaling $218 million and $310 million, respectively that expose PacifiCorp to the amounts presented on a net basis onrisk of increased interest expense in the Consolidated Balance Sheets (in millions):
|
| | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2018: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 36 |
| | $ | 4 |
| | $ | 10 |
| | $ | 1 |
| | $ | 51 |
|
Commodity liabilities | (9 | ) | | (1 | ) | | (67 | ) | | (71 | ) | | (148 | ) |
Total | 27 |
| | 3 |
| | (57 | ) | | (70 | ) | | (97 | ) |
| | | | | | | | | |
Total derivatives | 27 |
| | 3 |
| | (57 | ) | | (70 | ) | | (97 | ) |
Cash collateral (payable) receivable | (2 | ) | | — |
| | 16 |
| | 45 |
| | 59 |
|
Total derivatives - net basis | $ | 25 |
| | $ | 3 |
| | $ | (41 | ) | | $ | (25 | ) | | $ | (38 | ) |
| | | | | | | | | |
As of December 31, 2017: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 11 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 13 |
|
Commodity liabilities | (3 | ) | | — |
| | (32 | ) | | (82 | ) | | (117 | ) |
Total | 8 |
| | 1 |
| | (31 | ) | | (82 | ) | | (104 | ) |
| | | | | | | | | |
Total derivatives | 8 |
| | 1 |
| | (31 | ) | | (82 | ) | | (104 | ) |
Cash collateral receivable | — |
| | — |
| | 17 |
| | 57 |
| | 74 |
|
Total derivatives - net basis | $ | 8 |
| | $ | 1 |
| | $ | (14 | ) | | $ | (25 | ) | | $ | (30 | ) |
| |
(1) | PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2018 and 2017, a regulatory asset of $96 million and $101 million, respectively, was recorded related to the net derivative liability of $97 million and $104 million, respectively. |
event of increases in short-term interest rates. The following table reconciles the beginning and ending balances ofmarket risk related to PacifiCorp's regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in regulatory assets, as well as amounts reclassified to earnings for the years ended December 31 (in millions):
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Beginning balance | $ | 101 |
| | $ | 73 |
| | $ | 133 |
|
Changes in fair value recognized in regulatory assets | 12 |
| | 47 |
| | (27 | ) |
Net (losses) gains reclassified to operating revenue | (68 | ) | | 9 |
| | 10 |
|
Net gains (losses) reclassified to energy costs | 51 |
| | (28 | ) | | (43 | ) |
Ending balance | $ | 96 |
| | $ | 101 |
| | $ | 73 |
|
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market valuesvariable-rate debt as of December 31, (in millions):2021 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on PacifiCorp's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
|
| | | | | | | |
| Unit of | | | | |
| Measure | | 2018 | | 2017 |
| | | | | |
Electricity sales | Megawatt hours | | (6 | ) | | (9 | ) |
Natural gas purchases | Decatherms | | 117 |
| | 113 |
|
Fuel oil purchases | Gallons | | — |
| | — |
|
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2018,2021, PacifiCorp's aggregate credit ratingsexposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PacifiCorp and subsidiaries ("PacifiCorp") as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of PacifiCorp as of December 31, 2021 and 2020, and the results of its senior secured debtoperations and its issuer credit ratingscash flows for senior unsecured debteach of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of PacifiCorp's management. Our responsibility is to express an opinion on PacifiCorp's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. PacifiCorp is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of PacifiCorp's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by Moody's Investor Service and Standard & Poor's Rating Services were investment grade.management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The aggregate fair valuecritical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
PacifiCorp is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to rates in the respective service territories where PacifiCorp operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense; and income tax expense (benefit).
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow PacifiCorp an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While PacifiCorp has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit PacifiCorp's derivative contractsability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated PacifiCorp's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability positionsbalances for completeness.
•For regulatory matters in process, we inspected PacifiCorp's filings with specific credit-risk-related contingent features totaled $113 millionthe Commissions and $110the filings with the Commissions by intervenors that may impact PacifiCorp's future rates, for any evidence that might contradict management's assertions.
We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
California and Oregon 2020 Wildfires – Contingencies – See Note 14 to the financial statements
Critical Audit Matter Description
PacifiCorp has loss contingencies related to the California and Oregon 2020 wildfires (the "2020 wildfires"). PacifiCorp has recorded estimated liabilities, net of expected insurance recoveries, of $136 million as of December 31, 20182021, which represents its best estimate of probable losses, net of expected insurance recoveries, as a result of the 2020 wildfires.
We identified wildfire-related contingencies and 2017, respectively, for which PacifiCorp had posted collateral of $61 million and $74 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggeredrelated disclosure as of December 31, 2018 and 2017, PacifiCorp would have been required to post $35 million and $34 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
| |
(12) | Fair Value Measurements
|
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair valuea critical audit matter because of the short-term maturitysignificant judgments made by management to estimate the losses. This required the application of a high degree of judgment and extensive effort when performing audit procedures to evaluate the reasonableness of management's estimate of the losses and disclosure related to wildfire-related loss contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding its estimate of losses for wildfire-related contingencies and the related disclosure included the following, among others:
•We evaluated management's judgments related to whether a loss was probable and reasonably estimable, reasonably possible, or remote for each individual wildfire by inquiring of management and PacifiCorp's external and internal legal counsel regarding the amounts of probable and reasonably estimable, reasonably possible, and remote losses, including the potential impact of information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire, and external information for any evidence that might contradict management's assertions.
•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management and its external and internal legal counsel.
•We tested the significant assumptions used in determining the estimate, including, but not limited to, information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire.
•We read legal letters from PacifiCorp's external and internal legal counsel regarding information regarding ongoing litigation related to the 2020 wildfires and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated whether PacifiCorp's disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ Deloitte & Touche LLP
Portland, Oregon
February 25, 2022
We have served as PacifiCorp's auditor since 2006.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 179 | | | $ | 13 | |
Trade receivables, net | 725 | | | 703 | |
Other receivables, net | 52 | | | 48 | |
Inventories | 474 | | | 482 | |
Regulatory assets | 65 | | | 116 | |
Prepaid expenses | 79 | | | 79 | |
Other current assets | 147 | | | 82 | |
Total current assets | 1,721 | | | 1,523 | |
| | | |
Property, plant and equipment, net | 22,914 | | | 22,430 | |
Regulatory assets | 1,287 | | | 1,279 | |
Other assets | 534 | | | 470 | |
| | | |
Total assets | $ | 26,456 | | | $ | 25,702 | |
The accompanying notes are an integral part of these instruments. consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | |
Current liabilities: | | | |
Accounts payable | $ | 680 | | | $ | 772 | |
Accrued interest | 121 | | | 127 | |
Accrued property, income and other taxes | 78 | | | 80 | |
Accrued employee expenses | 89 | | | 84 | |
Short-term debt | — | | | 93 | |
Current portion of long-term debt | 155 | | | 420 | |
Regulatory liabilities | 118 | | | 115 | |
Other current liabilities | 219 | | | 174 | |
Total current liabilities | 1,460 | | | 1,865 | |
| | | |
Long-term debt | 8,575 | | | 8,192 | |
Regulatory liabilities | 2,650 | | | 2,727 | |
Deferred income taxes | 2,847 | | | 2,627 | |
Other long-term liabilities | 1,011 | | | 1,118 | |
Total liabilities | 16,543 | | | 16,529 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholders' equity: | | | |
Preferred stock | 2 | | | 2 | |
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 4,479 | | | 4,479 | |
Retained earnings | 5,449 | | | 4,711 | |
Accumulated other comprehensive loss, net | (17) | | | (19) | |
Total shareholders' equity | 9,913 | | | 9,173 | |
| | | |
Total liabilities and shareholders' equity | $ | 26,456 | | | $ | 25,702 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 1,831 | | | 1,790 | | | 1,795 | |
Operations and maintenance | 1,031 | | | 1,209 | | | 1,048 | |
Depreciation and amortization | 1,088 | | | 1,209 | | | 954 | |
Property and other taxes | 213 | | | 209 | | | 199 | |
Total operating expenses | 4,163 | | | 4,417 | | | 3,996 | |
| | | | | |
Operating income | 1,133 | | | 924 | | | 1,072 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (430) | | | (426) | | | (401) | |
Allowance for borrowed funds | 24 | | | 48 | | | 36 | |
Allowance for equity funds | 50 | | | 98 | | | 72 | |
Interest and dividend income | 24 | | | 10 | | | 21 | |
Other, net | 8 | | | 10 | | | 32 | |
Total other expense | (324) | | | (260) | | | (240) | |
| | | | | |
Income before income tax (benefit) expense | 809 | | | 664 | | | 832 | |
Income tax (benefit) expense | (79) | | | (75) | | | 61 | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
| | | | | |
Other comprehensive income (loss), net of tax — | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $1, $(1) and $(1) | 2 | | | (3) | | | (3) | |
| | | | | |
Comprehensive income | $ | 890 | | | $ | 736 | | | $ | 768 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated | | |
| | | | | Additional | | | | Other | | Total |
| Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2018 | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 3,377 | | | $ | (13) | | | $ | 7,845 | |
Net income | — | | | — | | | — | | | 771 | | | — | | | 771 | |
Other comprehensive loss | — | | | — | | | — | | | (1) | | | (3) | | | (4) | |
Common stock dividends declared | — | | | — | | | — | | | (175) | | | — | | | (175) | |
Balance, December 31, 2019 | 2 | | | — | | | 4,479 | | | 3,972 | | | (16) | | | 8,437 | |
Net income | — | | | — | | | — | | | 739 | | | — | | | 739 | |
Other comprehensive loss | — | | | — | | | — | | | — | | | (3) | | | (3) | |
| | | | | | | | | | | |
Balance, December 31, 2020 | 2 | | | — | | | 4,479 | | | 4,711 | | | (19) | | | 9,173 | |
Net income | — | | | — | | | — | | | 888 | | | — | | | 888 | |
Other comprehensive income | — | | | — | | | — | | | — | | | 2 | | | 2 | |
Common stock dividends declared | — | | | — | | | — | | | (150) | | | — | | | (150) | |
Balance, December 31, 2021 | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,449 | | | $ | (17) | | | $ | 9,913 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
Adjustments to reconcile net income to net cash flows from operating | | | | | |
activities: | | | | | |
Depreciation and amortization | 1,088 | | | 1,209 | | | 954 | |
Allowance for equity funds | (50) | | | (98) | | | (72) | |
Changes in regulatory assets and liabilities | (189) | | | (229) | | | (55) | |
Deferred income taxes and amortization of investment tax credits | 64 | | | (124) | | | (131) | |
Other, net | (5) | | | 1 | | | 20 | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables, other receivables and other assets | 15 | | | (154) | | | 26 | |
Inventories | 8 | | | (88) | | | 23 | |
Prepaid expenses | 2 | | | (15) | | | (12) | |
Derivative collateral, net | 19 | | | 23 | | | 12 | |
Accrued property, income and other taxes, net | (37) | | | (53) | | | 22 | |
Accounts payable and other liabilities | 1 | | | 372 | | | (11) | |
Net cash flows from operating activities | 1,804 | | | 1,583 | | | 1,547 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (1,513) | | | (2,540) | | | (2,175) | |
Other, net | 12 | | | 30 | | | 11 | |
Net cash flows from investing activities | (1,501) | | | (2,510) | | | (2,164) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 984 | | | 987 | | | 989 | |
Repayments of long-term debt | (870) | | | (38) | | | (350) | |
(Repayments of) net proceeds from short-term debt | (93) | | | (37) | | | 100 | |
| | | | | |
Dividends paid | (150) | | | — | | | (175) | |
Other, net | (7) | | | (2) | | | (3) | |
Net cash flows from financing activities | (136) | | | 910 | | | 561 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 167 | | | (17) | | | (56) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 19 | | | 36 | | | 92 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 186 | | | $ | 19 | | | $ | 36 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)Organization and Operations
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has variousinterests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2)Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") described in Note 14. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are measuredestablished to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Investments
Available-for-sale securities are carried at fair value with realized gains and losses, as determined on the Consolidated Financial Statements using inputs from the three levelsa specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of thetax. As of December 31, 2021 and 2020, PacifiCorp had 0 unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value hierarchy. A financial asset or liability classification withinwith realized and unrealized gains and losses recognized in earnings.
Equity Method Investments
PacifiCorp utilizes the hierarchy is determined based on the lowest level input that is significantequity method of accounting with respect to the fair value measurement. The three levels are as follows:
Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp hasinvestments when it possesses the ability to accessexercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, PacifiCorp records the investment at cost and subsequently increases or decreases the carrying value of the investment by PacifiCorp's proportionate share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. PacifiCorp records dividends or other equity distributions as reductions in the carrying value of the investment.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination, and are stated at the measurement date.
Level 2 - Inputs include quoted pricesoutstanding principal amount, net of an estimated allowance for similar assets or liabilities in active markets, quoted pricescredit losses. The allowance for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputscredit losses is based on PacifiCorp's assessment of the best information available, includingcollectability of amounts owed to PacifiCorp by its own data.
customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The following table presents PacifiCorp's assets and liabilities recognizedchange in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, and measured at fair value on a recurring basisis summarized as follows for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 17 | | | $ | 8 | | | $ | 8 | |
Charged to operating costs and expenses, net | 13 | | | 18 | | | 13 | |
Write-offs, net | (12) | | | (9) | | | (13) | |
Ending balance | $ | 18 | | | $ | 17 | | | $ | 8 | |
|
| | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2018: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — |
| | $ | 51 |
| | $ | — |
| | $ | (23 | ) | | $ | 28 |
|
Money market mutual funds(2) | 69 |
| | — |
| | — |
| | — |
| | 69 |
|
Investment funds | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| $ | 93 |
| | $ | 51 |
| | $ | — |
| | $ | (23 | ) | | $ | 121 |
|
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — |
| | $ | (148 | ) | | $ | — |
| | $ | 82 |
| | $ | (66 | ) |
| | | | | | | | | |
As of December 31, 2017: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | (4 | ) | | $ | 9 |
|
Money market mutual funds (2) | 21 |
| | — |
| | — |
| | — |
| | 21 |
|
Investment funds | 21 |
| | — |
| | — |
| | — |
| | 21 |
|
| $ | 42 |
| | $ | 13 |
| | $ | — |
| | $ | (4 | ) | | $ | 51 |
|
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — |
| | $ | (117 | ) | | $ | — |
| | $ | 78 |
| | $ | (39 | ) |
| |
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $59 million and $74 million as of December 31, 2018 and 2017, respectively. |
| |
(2) | Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Derivatives
PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or energy costs on the Consolidated Statements of Operations.
For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates are recorded as regulatory liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials, supplies and fuel stocks and are stated at the lower of average cost or net realizable value.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction ("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when PacifiCorp retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of property, plant and equipment, is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
PacifiCorp evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment supports PacifiCorp's regulated businesses the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
PacifiCorp's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Revenue Recognition
PacifiCorp uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging."
Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $264 million and $254 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Berkshire Hathaway includes PacifiCorp in its consolidated United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. PacifiCorp's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
(3)Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
Generation | 15 - 59 years | | $ | 13,679 | | | $ | 12,861 | |
Transmission | 60 - 90 years | | 7,894 | | | 7,632 | |
Distribution | 20 - 75 years | | 8,044 | | | 7,660 | |
Intangible plant(1) | 5 - 75 years | | 1,106 | | | 1,054 | |
Other | 5 - 60 years | | 1,539 | | | 1,510 | |
Utility plant in-service | | | 32,262 | | | 30,717 | |
Accumulated depreciation and amortization | | | (10,507) | | | (9,838) | |
Utility plant in-service, net | | | 21,755 | | | 20,879 | |
Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 9 | |
Plant, net | | | 21,773 | | | 20,888 | |
Construction work-in-progress | | | 1,141 | | | 1,542 | |
Property, plant and equipment, net | | | $ | 22,914 | | | $ | 22,430 | |
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
The average depreciation and amortization rate applied to depreciable property, plant and equipment was 3.5%, 4.1% and 3.3% for the years ended December 31, 2021, 2020 and 2019, respectively, including the impacts of accelerated depreciation totaling $376 million and $125 million in 2020 and 2019, respectively, for Utah's share of certain thermal plant units in 2020, including Cholla Unit No. 4 in 2020 for which operations ceased in December 2020; Oregon's and Idaho's shares of Cholla Unit No. 4 in 2020; and Oregon's share of certain retired wind equipment associated with wind repowering projects in 2020 and 2019. As discussed in Notes 6 and 9, existing regulatory liabilities primarily associated with the Utah Sustainability and Transportation Plan ("STEP") and 2017 Tax Reform benefits were utilized to accelerate depreciation of these assets.
Effective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase in depreciation expense of approximately $158 million for the year ended December 31, 2021, as compared to the year ended December 31, 2020, based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.
Unallocated Acquisition Adjustments
PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in property, plant and equipment purchased from the entity that first dedicated the assets to utility service over their net book value in those assets. These unallocated acquisition adjustments included in other property, plant and equipment had an original cost of $156 million as of December 31, 2021 and 2020, and accumulated depreciation of $143 million and $140 million as of December 31, 2021 and 2020, respectively.
(4)Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include PacifiCorp's share of the expenses of these facilities.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Facility | | Accumulated | | Construction |
| PacifiCorp | | in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Jim Bridger Nos. 1 - 4 | 67 | % | | $ | 1,523 | | | $ | 812 | | | $ | 15 | |
Hunter No. 1 | 94 | | | 489 | | | 221 | | | 8 | |
Hunter No. 2 | 60 | | | 306 | | | 138 | | | 1 | |
Wyodak | 80 | | | 477 | | | 269 | | | 8 | |
Colstrip Nos. 3 and 4 | 10 | | | 260 | | | 161 | | | 3 | |
Hermiston | 50 | | | 185 | | | 99 | | | — | |
Craig Nos. 1 and 2 | 19 | | | 369 | | | 319 | | | — | |
Hayden No. 1 | 25 | | | 77 | | | 47 | | | — | |
Hayden No. 2 | 13 | | | 44 | | | 28 | | | — | |
| | | | | | | |
Transmission and distribution facilities | Various | | 879 | | | 269 | | | 118 | |
Total | | | $ | 4,609 | | | $ | 2,363 | | | $ | 153 | |
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheets as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 11 | | | $ | 11 | |
Finance leases | 11 | | | 17 | |
Total right-of-use assets | $ | 22 | | | $ | 28 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 11 | | | $ | 11 | |
Finance leases | 12 | | | 17 | |
Total lease liabilities | $ | 23 | | | $ | 28 | |
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 56 | | | $ | 60 | | | $ | 77 | |
Operating | 3 | | | 3 | | | 3 | |
Finance: | | | | | |
Amortization | 5 | | | 2 | | | 1 | |
Interest | 2 | | | 2 | | | 2 | |
Short-term | 3 | | | 1 | | | 2 | |
Total lease costs | $ | 69 | | | $ | 68 | | | $ | 85 | |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 12.7 | | 13.9 | | 14.0 |
Finance leases | 10.1 | | 8.4 | | 9.1 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 3.7 | % | | 3.8 | % | | 3.7 | % |
Finance leases | 11.1 | % | | 10.5 | % | | 10.6 | % |
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2021, 2020 and 2019.
PacifiCorp has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 3 | | | $ | 3 | | | $ | 6 | |
2023 | 2 | | | 2 | | | 4 | |
2024 | 1 | | | 2 | | | 3 | |
2025 | 1 | | | 2 | | | 3 | |
2026 | 1 | | | 2 | | | 3 | |
Thereafter | 6 | | | 10 | | | 16 | |
Total undiscounted lease payments | 14 | | | 21 | | | 35 | |
Less - amounts representing interest | (3) | | | (9) | | | (12) | |
Lease liabilities | $ | 11 | | | $ | 12 | | | $ | 23 | |
(6)Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2021 | | 2020 |
| | | | | |
| | | | | |
Employee benefit plans(1) | 17 years | | $ | 286 | | | $ | 432 | |
Utah mine disposition(2) | Various | | 116 | | | 117 | |
Unamortized contract values | 2 years | | 36 | | | 42 | |
Deferred net power costs | 2 years | | 151 | | | 78 | |
Unrealized loss on derivative contracts | N/A | | — | | | 17 | |
Environmental costs | 28 years | | 108 | | | 89 | |
Asset retirement obligation | 29 years | | 241 | | | 252 | |
Demand side management (DSM)(3) | 10 years | | 211 | | | 196 | |
Other | Various | | 203 | | | 172 | |
Total regulatory assets | | | $ | 1,352 | | | $ | 1,395 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 65 | | | $ | 116 | |
Noncurrent assets | | | 1,287 | | | 1,279 | |
Total regulatory assets | | | $ | 1,352 | | | $ | 1,395 | |
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.
(2)Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the United Mine Workers of America ("UMWA") 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery.
(3)In accordance with the Utah general rate case order issued in December 2020, $185 million of amounts billed to Utah customers under the Utah STEP program were used to accelerate depreciation of certain coal-fueled generation units as discussed in Note 3.
PacifiCorp had regulatory assets not earning a return on investment of $723 million and $707 million as of December 31, 2021 and 2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2021 | | 2020 |
| | | | | |
Cost of removal(1) | 26 years | | $ | 1,187 | | | $ | 1,125 | |
Deferred income taxes(2) | Various | | 1,307 | | | 1,463 | |
| | | | | |
Unrealized gain on regulated derivatives | 1 year | | 53 | | | — | |
Other | Various | | 221 | | | 254 | |
Total regulatory liabilities | | | $ | 2,768 | | | $ | 2,842 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 118 | | | $ | 115 | |
Noncurrent liabilities | | | 2,650 | | | 2,727 | |
Total regulatory liabilities | | | $ | 2,768 | | | $ | 2,842 | |
(1)Amounts represent estimated costs, as generally accrued through depreciation rates, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable of being passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(7)Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | |
2021: | | |
Credit facilities | | $ | 1,200 | |
Less: | | |
Short-term debt | | — | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | $ | 982 | |
| | |
2020: | | |
Credit facilities | | $ | 1,200 | |
Less: | | |
Short-term debt | | (93) | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | $ | 889 | |
As of December 31, 2021, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.
PacifiCorp has a $1.2 billion unsecured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. As of December 31, 2021, PacifiCorp did not have any commercial paper borrowings outstanding. As of December 31, 2020, PacifiCorp had $93 million of commercial paper outstanding with a weighted average interest rate of 0.16%.
The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2021 and 2020, PacifiCorp had $19 million and $11 million, respectively, of fully available letters of credit issued under committed arrangements in support of certain transactions required by third parties and generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
(8)Long-term Debt
PacifiCorp's long-term debt was as follows as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| | | | | Average | | | | Average |
| Principal | | Carrying | | Interest | | Carrying | | Interest |
| Amount | | Value | | Rate | | Value | | Rate |
| | | | | | | | | |
First mortgage bonds: | | | | | | | | | |
2.95% to 8.53%, due through 2026 | $ | 1,379 | | | $ | 1,378 | | | 4.52 | % | | $ | 2,245 | | | 4.12 | % |
2.70% to 7.70%, due 2027 to 2031 | 1,100 | | | 1,094 | | | 4.35 | | | 1,094 | | | 4.35 | |
5.25% to 6.10%, due 2032 to 2036 | 850 | | | 845 | | | 5.75 | | | 845 | | | 5.75 | |
5.75% to 6.35%, due 2037 to 2041 | 2,150 | | | 2,137 | | | 6.05 | | | 2,137 | | | 6.05 | |
4.10% due 2042 | 300 | | | 297 | | | 4.10 | | | 297 | | | 4.10 | |
2.90% to 4.15%, due 2049 to 2052 | 2,800 | | | 2,761 | | | 3.52 | | | 1,776 | | | 3.86 | |
Variable-rate series, tax-exempt bond obligations (2021-0.12% to 0.13%; 2020-0.14% to 0.16%): | | | | | | | | | |
Due 2025 | 25 | | | 25 | | | 0.12 | | | 25 | | | 0.14 | |
Due 2024 to 2025(1) | 193 | | | 193 | | | 0.13 | | | 193 | | | 0.15 | |
Total long-term debt | $ | 8,797 | | | $ | 8,730 | | | | | $ | 8,612 | | | |
| | | | | | | | | | | |
Reflected as: | | | |
| 2021 | | 2020 |
Current portion of long-term debt | $ | 155 | | | $ | 420 | |
Long-term debt | 8,575 | | | 8,192 | |
Total long-term debt | $ | 8,730 | | | $ | 8,612 | |
(1)Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the United States Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2023.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $31 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2021.
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
As of December 31, 2021, the annual principal maturities of long-term debt for 2022 and thereafter are as follows (in millions):
| | | | | |
| Long-term |
| Debt |
| |
2022 | $ | 155 | |
2023 | 449 | |
2024 | 591 | |
2025 | 302 | |
2026 | 100 | |
Thereafter | 7,200 | |
Total | 8,797 | |
Unamortized discount and debt issuance costs | (67) | |
| |
Total | $ | 8,730 | |
(9)Income Taxes
Income tax (benefit) expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current: | | | | | |
Federal | $ | (150) | | | $ | 19 | | | $ | 158 | |
State | 7 | | | 30 | | | 34 | |
Total | (143) | | | 49 | | | 192 | |
| | | | | |
Deferred: | | | | | |
Federal | 26 | | | (124) | | | (132) | |
State | 40 | | | 1 | | | 4 | |
Total | 66 | | | (123) | | | (128) | |
| | | | | |
Investment tax credits | (2) | | | (1) | | | (3) | |
Total income tax (benefit) expense | $ | (79) | | | $ | (75) | | | $ | 61 | |
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
State income taxes, net of federal income tax benefit | 3 | | | 3 | | | 3 | |
Effects of ratemaking | (14) | | | (22) | | | (13) | |
Federal income tax credits | (20) | | | (13) | | | (3) | |
Other | — | | | — | | | (1) | |
Effective income tax rate | (10) | % | | (11) | % | | 7 | % |
Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $112 million for 2021, including the use of $4 million to amortize certain regulatory asset balances in Wyoming and Idaho. Excess deferred income tax amortization, net of deferrals, was $132 million for 2020, including the use of $118 million to accelerate depreciation of certain retired equipment and to amortize certain regulatory balances in Idaho, Oregon and Utah. Excess deferred income taxes amortization, net of deferrals, was $93 million for 2019, including the use of $91 million to accelerate depreciation of certain retired wind equipment for Oregon.
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 682 | | | $ | 700 | |
Employee benefits | 68 | | | 93 | |
| | | |
State carryforwards | 73 | | | 73 | |
Loss contingencies | 63 | | | 63 | |
Asset retirement obligations | 73 | | | 65 | |
Other | 73 | | | 83 | |
| 1,032 | | | 1,077 | |
Deferred income tax liabilities: | | | |
Property, plant and equipment | (3,468) | | | (3,311) | |
Regulatory assets | (332) | | | (343) | |
Other | (79) | | | (50) | |
| (3,879) | | | (3,704) | |
Net deferred income tax liability | $ | (2,847) | | | $ | (2,627) | |
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2021 (in millions):
| | | | | | | | |
| | State |
| | |
Net operating loss carryforwards | | $ | 1,138 | |
Deferred income taxes on net operating loss carryforwards | | $ | 53 | |
Expiration dates | | 2023 - 2032 |
| | |
Tax credit carryforwards | | $ | 20 | |
Expiration dates | | 2022 - indefinite |
The United States Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns through December 31, 2013. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31, 2011, with the exception of Idaho, where the statute has expired through December 31, 2017, for all adjustments other than federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
(10) Employee Benefit Plans
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover certain of its employees, as well as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.
Defined Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, collectively the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Pension Settlement
Pension settlement accounting was triggered in 2021 as a result of the amount of lump sum distributions in the Retirement Plan during 2021 exceeding the service and interest cost threshold. This resulted in an interim July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the settlement accounting, PacifiCorp recognized settlement losses of $6 million, net of regulatory deferrals during the year ended December 31, 2021.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | | $ | 2 | |
Interest cost | 29 | | | 36 | | | 44 | | | 7 | | | 9 | | | 12 | |
Expected return on plan assets | (51) | | | (56) | | | (67) | | | (9) | | | (14) | | | (21) | |
Settlement | 6 | | | — | | | — | | | — | | | — | | | — | |
Net amortization | 21 | | | 18 | | | 11 | | | 1 | | | 3 | | | — | |
Net periodic benefit cost (credit) | $ | 5 | | | $ | (2) | | | $ | (12) | | | $ | 1 | | | $ | — | | | $ | (7) | |
Funded Status
The following table is a reconciliation of the fair value of derivative contracts is estimated using unadjusted quoted pricesplan assets for identical contractsthe years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 1,064 | | | $ | 1,036 | | | $ | 327 | | | $ | 334 | |
Employer contributions(1) | 5 | | | 5 | | | 1 | | | — | |
Participant contributions | — | | | — | | | 6 | | | 4 | |
Actual return on plan assets | 109 | | | 124 | | | 14 | | | 15 | |
Settlement(2) | (52) | | | — | | | — | | | — | |
Benefits paid | (68) | | | (101) | | | (24) | | | (26) | |
Plan assets at fair value, end of year | $ | 1,058 | | | $ | 1,064 | | | $ | 324 | | | $ | 327 | |
(1)Amounts represent employer contributions to the SERP.
(2)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 1,202 | | | $ | 1,167 | | | $ | 307 | | | $ | 304 | |
Service cost | — | | | — | | | 2 | | | 2 | |
Interest cost | 29 | | | 36 | | | 7 | | | 9 | |
Participant contributions | — | | | — | | | 6 | | | 4 | |
Actuarial (gain) loss | (63) | | | 100 | | | (10) | | | 14 | |
| | | | | | | |
Settlement(1) | (52) | | | — | | | — | | | — | |
| | | | | | | |
Benefits paid | (68) | | | (101) | | | (24) | | | (26) | |
Benefit obligation, end of year | $ | 1,048 | | | $ | 1,202 | | | $ | 288 | | | $ | 307 | |
Accumulated benefit obligation, end of year | $ | 1,048 | | | $ | 1,202 | | | | | |
(1)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 1,058 | | | $ | 1,064 | | | $ | 324 | | | $ | 327 | |
Less - Benefit obligation, end of year | 1,048 | | | 1,202 | | | 288 | | | 307 | |
Funded status | $ | 10 | | | $ | (138) | | | $ | 36 | | | $ | 20 | |
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 63 | | | $ | 8 | | | $ | 36 | | | $ | 20 | |
Accrued employee expenses | (4) | | | (4) | | | — | | | — | |
Other long-term liabilities | (49) | | | (142) | | | — | | | — | |
Amounts recognized | $ | 10 | | | $ | (138) | | | $ | 36 | | | $ | 20 | |
The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market in which PacifiCorp transacts. When quoted prices for identical contractsvalue of other Rabbi trust investments, was $69 million and $61 million as of December 31, 2021 and 2020, respectively. These assets are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimatesincluded in the plan assets in the above table, but are reflected in noncurrent other assets as of December 31, 2021 and 2020, respectively, on the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable forConsolidated Balance Sheets.
As of December 31, 2021, the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contractsthe plan assets for the Retirement Plan was in excess of both the projected benefit obligation and the accumulated benefit obligation.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net loss (gain) | $ | 298 | | | $ | 455 | | | $ | (28) | | | $ | (13) | |
| | | | | | | |
Regulatory deferrals(1) | 11 | | | 2 | | | 2 | | | 3 | |
Total | $ | 309 | | | $ | 457 | | | $ | (26) | | | $ | (10) | |
(1)Includes $9 million of deferrals associated with 2021 pension settlement losses.
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2021 and 2020 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | | | Comprehensive | | |
| Asset | | | | Loss | | Total |
Pension | | | | | | | |
Balance, December 31, 2019 | $ | 422 | | | | | $ | 21 | | | $ | 443 | |
Net loss arising during the year | 27 | | | | | 5 | | | 32 | |
| | | | | | | |
Net amortization | (17) | | | | | (1) | | | (18) | |
| | | | | | | |
Total | 10 | | | | | 4 | | | 14 | |
Balance, December 31, 2020 | 432 | | | | | 25 | | | 457 | |
Net gain arising during the year | (120) | | | | | (1) | | | (121) | |
| | | | | | | |
Net amortization | (20) | | | | | (1) | | | (21) | |
Settlement | (6) | | | | | — | | | (6) | |
Total | (146) | | | | | (2) | | | (148) | |
Balance, December 31, 2021 | $ | 286 | | | | | $ | 23 | | | $ | 309 | |
| | | | | |
| Regulatory |
| Liability |
Other Postretirement | |
Balance, December 31, 2019 | $ | (20) | |
Net loss arising during the year | 13 | |
| |
Net amortization | (3) | |
Total | 10 | |
Balance, December 31, 2020 | (10) | |
Net gain arising during the year | (15) | |
| |
Net amortization | (1) | |
Total | (16) | |
Balance, December 31, 2021 | $ | (26) | |
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 2.90 | % | | 2.50 | % | | 3.25 | % | | 2.90 | % | | 2.50 | % | | 3.20 | % |
Rate of compensation increase | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan - non-union | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.40 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.27 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2021 | 0.82 | % | | 0.82 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2022 | 0.88 | % | | 0.82 | % | | 2.10 | % | | N/A | | N/A | | N/A |
2023 | 0.88 | % | | 2.00 | % | | 2.10 | % | | N/A | | N/A | | N/A |
2024 and beyond | 1.90 | % | | 2.00 | % | | 2.10 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Interest crediting rates for cash balance plan - union | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.15 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.16 | % | | 2.16 | % | | N/A | | N/A | | N/A |
2021 | 1.42 | % | | 1.42 | % | | 2.16 | % | | N/A | | N/A | | N/A |
2022 | 1.94 | % | | 1.42 | % | | 2.70 | % | | N/A | | N/A | | N/A |
2023 | 1.94 | % | | 2.40 | % | | 2.70 | % | | N/A | | N/A | | N/A |
2024 and beyond | 2.30 | % | | 2.40 | % | | 2.70 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | |
Discount rate | 2.50 | % | | 3.25 | % | | 4.25 | % | | 2.50 | % | | 3.20 | % | | 4.25 | % |
Expected return on plan assets | 6.00 | | | 6.50 | | | 7.00 | | | 2.90 | | | 4.92 | | | 6.86 | |
| | | | | | | | | | | |
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
As a functionresult of a plan amendment effective on January 1, 2017, the benefit obligation for the Retirement Plan is no longer affected by future increases in compensation. As a result of a labor settlement reached with UMWA in December 2014, the benefit obligation for the other postretirement plan is no longer affected by healthcare cost trends.
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $— million, respectively, during 2022. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension Protection Act of 2006, as amended ("PPA of 2006"). PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the PPA of 2006. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2022 through 2026 and for the five years thereafter are summarized below (in millions):
| | | | | | | | | | | |
| Projected Benefit Payments |
| Pension | | Other Postretirement |
| | | |
2022 | $ | 96 | | | $ | 24 | |
2023 | 85 | | | 23 | |
2024 | 79 | | | 22 | |
2025 | 76 | | | 21 | |
2026 | 71 | | | 20 | |
2027-2031 | 304 | | | 87 | |
Plan Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
In 2020, the assets of the PacifiCorp Master Retirement Trust were transferred into the BHE Master Retirement Trust.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2021:
| | | | | | | | | | | |
| Pension(1) | | Other Postretirement(1) |
| % | | % |
Debt securities(2) | 55 - 85 | | 70 - 80 |
Equity securities(2) | 25- 35 | | 20 - 30 |
Other | 0 - 10 | | 0 - 1 |
| | | |
(1)The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthinessinvestments in debt and durationequity securities.
Fair Value Measurements
The following table presents the fair value of contracts. plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2021: | | | | | | | | |
Cash equivalents | | $ | — | | | $ | 15 | | | $ | — | | | $ | 15 | |
Debt securities: | | | | | | | | |
United States government obligations | | 51 | | | — | | | — | | | 51 | |
| | | | | | | | |
Corporate obligations | | — | | | 299 | | | — | | | 299 | |
Municipal obligations | | — | | | 22 | | | — | | | 22 | |
Agency, asset and mortgage-backed obligations | | — | | | 38 | | | — | | | 38 | |
Equity securities: | | | | | | | | |
United States companies | | 61 | | | — | | | — | | | 61 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 112 | | | $ | 374 | | | $ | — | | | $ | 486 | |
Investment funds(2) measured at net asset value | | | | | | | | 538 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 34 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 1,058 | |
| | | | | | | | |
As of December 31, 2020: | | | | | | | | |
Cash equivalents | | $ | — | | | $ | 32 | | | $ | — | | | $ | 32 | |
Debt securities: | | | | | | | | |
United States government obligations | | 14 | | | — | | | — | | | 14 | |
International government obligations | | — | | | — | | | — | | | — | |
Corporate obligations | | — | | | 231 | | | — | | | 231 | |
Municipal obligations | | — | | | 21 | | | — | | | 21 | |
| | | | | | | | |
Equity securities: | | | | | | | | |
United States companies | | 91 | | | — | | | — | | | 91 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 105 | | | $ | 284 | | | $ | — | | | $ | 389 | |
Investment funds(2) measured at net asset value | | | | | | | | 587 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 88 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 1,064 | |
(1)Refer to Note 1113 for furtheradditional discussion regarding PacifiCorp's risk management and hedging activities.the three levels of the fair value hierarchy.
PacifiCorp's investments in money market(2)Investment funds are substantially comprised of mutual funds and investmentcollective trust funds. These funds consist of equity and debt securities of approximately 59% and 41%, respectively, for 2021 and 78% and 22%, respectively, for 2020, and are invested in United States and international securities of approximately 84% and 16%, respectively, for 2021 and 74% and 26%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate.
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2021: | | | | | | | | |
Cash and cash equivalents | | $ | 4 | | | $ | 1 | | | $ | — | | | $ | 5 | |
Debt securities: | | | | | | | | |
United States government obligations | | 24 | | | — | | | — | | | 24 | |
| | | | | | | | |
Corporate obligations | | — | | | 79 | | | — | | | 79 | |
Municipal obligations | | — | | | 15 | | | — | | | 15 | |
Agency, asset and mortgage-backed obligations | | — | | | 35 | | | — | | | 35 | |
Equity securities: | | | | | | | | |
United States companies | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 32 | | | $ | 130 | | | $ | — | | | 162 | |
Investment funds(2) measured at net asset value | | | | | | | | 161 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 1 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 324 | |
| | | | | | | | |
As of December 31, 2020: | | | | | | | | |
Cash and cash equivalents | | $ | 8 | | | $ | 1 | | | $ | — | | | $ | 9 | |
Debt securities: | | | | | | | | |
United States government obligations | | 11 | | | — | | | — | | | 11 | |
| | | | | | | | |
Corporate obligations | | — | | | 86 | | | — | | | 86 | |
Municipal obligations | | — | | | 16 | | | — | | | 16 | |
Agency, asset and mortgage-backed obligations | | — | | | 44 | | | — | | | 44 | |
Equity securities: | | | | | | | | |
United States companies | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 23 | | | $ | 147 | | | $ | — | | | 170 | |
Investment funds(2) measured at net asset value | | | | | | | | 153 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 4 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 327 | |
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are stated at fair valuesubstantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 39% and 61%, respectively, for 2021 and 38% and 62%, respectively, for 2020, and are invested in United States and international securities of approximately 90% and 10%, respectively, for 2021 and 93% and 7%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily accounted for as available-for-sale securities. When available, PacifiCorp usesin real estate, buyout, growth equity and venture capital.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security,For level 2 investments, the fair value is determined using pricing models or net asset values based on observable market inputsinputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and quoted market prices of securities with similar characteristics.
PacifiCorp's long-term debt is carriedcommingled trust funds and investment entities are reported at costfair value based on the Consolidated Balance Sheets. Thenet asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because ofunderlying assets held by the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):fund less its liabilities.
|
| | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 7,015 |
| | $ | 7,833 |
| | $ | 7,005 |
| | $ | 8,370 |
|
(13)Commitments and Contingencies
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectric systemPacifiCorp is currently operating under annual licenses witha party to the FERC. In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed the2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"). Among, which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other things, the KHSA provided that the United States Department of the Interior would conduct scientific and engineering studiesstakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the Klamath hydroelectric system's mainstem dams wassettlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in the public interest and would advance restorationCalifornia bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Klamath Basin's salmonid fisheries. If it is determinedFederal Energy Regulatory Commission ("FERC") license to a third-party dam removal should proceed, dam removal would begin no earlier than 2020.
Congress failed to pass legislation needed to implement the original KHSA. In April 2016, the principal parties to the KHSA (PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce) executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, in September 2016, PacifiCorp andentity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a private, independent nonprofit 501(c)(3) organization formed by certain signatories of the amended KSHA, jointly filed anjoint application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilitiesdams from PacifiCorp to the KRRC. Also in September 2016, the KRRC filed an application with theThe FERC to surrender the license and decommission the same four facilities. The KRRC's license surrender application included a request for the FERC to refrain from acting on the surrender application until after theapproved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, is effective. In March 2018, the FERC issued an order splittingKaruk Tribe, the existingYurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application to remove PacifiCorp from the license for the Klamath Hydroelectric Project into two licenses:and add the Klamath Project (P‑2082) contains East Side, West Side, KenoStates and Fall Creek developments;KRRC as co-licensees for the new Lower Klamath Project (P‑14803) contains J.C. Boyle, Copco No. 1, Copco No. 2purposes of surrender. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and Iron Gate developments.the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In the same order,June 2021, the FERC deferred consideration of theapproved transfer of the license for the Lowerfour mainstem Klamath facilitiesdams from PacifiCorp to the KRRC until some point inand the future.States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp is currentlynotified the licensee for both the Klamath Project and Lower Klamath Project facilities and will retain ownershipPublic Service Commission of Utah of the Klamath Project facilities afterproperty transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the approval and transferissuance of the Lower Klamath Project facilities. In April 2018, PacifiCorp filed a motion to stay the effective date of the license amendment until transfer is approved. In June 2018,surrender from the FERC granted PacifiCorp's motion to stay the effective date of the Lower Klamath Project license and all related compliance obligations, pending a FERC order on the license transfer. Meanwhile, the FERC continues to assess the KRRC's capacity to become a project licensee for purposes of dam removal. The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, on January 25, 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project, relicensing. PacifiCorp is evaluating the impact of this decision.which remains pending.
Under the amended KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution toward facilities removal costs are being drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and the state of California, sufficient funds would need to be provided by the KRRC or an entity other than PacifiCorp for removal to proceed.
If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.
As of December 31, 2018,2021, PacifiCorp's assets included $44$14 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through either December 31, 2019, or December 31, 2022, depending upon the state jurisdiction.2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities. PacifiCorp estimates it is obligatedfacilities, which are estimated to make capital expenditures ofbe approximately $155$193 million over the next 10 years. Included in these estimates are commitments associated with the KHSA.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
(17) Revenue from Contracts with Customers
Energy Products and Services
The following table summarizes the Company's energy products and services Customer Revenue by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 22, for the years ended December 31 (in millions):
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| | 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,847 | | | $ | 2,128 | | | $ | 2,828 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 9,801 | |
Retail Gas | | — | | | 859 | | | 115 | | | — | | | — | | | — | | | — | | | — | | | 974 | |
Wholesale | | 157 | | | 454 | | | 62 | | | — | | | 57 | | | — | | | — | | | (3) | | | 727 | |
Transmission and distribution | | 143 | | | 58 | | | 74 | | | 1,023 | | | — | | | 702 | | | — | | | — | | | 2,000 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 2,404 | | | — | | | — | | | (131) | | | 2,273 | |
Other | | 108 | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | 1 | | | 109 | |
Total Regulated | | 5,255 | | | 3,499 | | | 3,080 | | | 1,023 | | | 2,460 | | | 702 | | | — | | | (135) | | | 15,884 | |
Nonregulated | | — | | | 15 | | | 3 | | | 43 | | | 956 | | | 35 | | | 796 | | | 576 | | | 2,424 | |
Total Customer Revenue | | 5,255 | | | 3,514 | | | 3,083 | | | 1,066 | | | 3,416 | | | 737 | | | 796 | | | 441 | | | 18,308 | |
Other revenue | | 41 | | | 33 | | | 24 | | | 122 | | | 128 | | | (6) | | | 185 | | | 100 | | | 627 | |
Total | | $ | 5,296 | | | $ | 3,547 | | | $ | 3,107 | | | $ | 1,188 | | | $ | 3,544 | | | $ | 731 | | | $ | 981 | | | $ | 541 | | | $ | 18,935 | |
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| | 2020 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,932 | | | $ | 1,924 | | | $ | 2,566 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 9,421 | |
Retail Gas | | — | | | 505 | | | 114 | | | — | | | — | | | — | | | — | | | — | | | 619 | |
Wholesale | | 107 | | | 199 | | | 45 | | | — | | | 17 | | | — | | | — | | | (2) | | | 366 | |
Transmission and distribution | | 96 | | | 60 | | | 95 | | | 887 | | | — | | | 641 | | | — | | | — | | | 1,779 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 1,397 | | | — | | | — | | | (139) | | | 1,258 | |
Other | | 108 | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | 110 | |
Total Regulated | | 5,243 | | | 2,688 | | | 2,822 | | | 887 | | | 1,414 | | | 641 | | | — | | | (142) | | | 13,553 | |
Nonregulated | | — | | | 16 | | | 2 | | | 26 | | | 134 | | | 18 | | | 817 | | | 515 | | | 1,528 | |
Total Customer Revenue | | 5,243 | | | 2,704 | | | 2,824 | | | 913 | | | 1,548 | | | 659 | | | 817 | | | 373 | | | 15,081 | |
Other revenue | | 98 | | | 24 | | | 30 | | | 109 | | | 30 | | | — | | | 119 | | | 65 | | | 475 | |
Total | | $ | 5,341 | | | $ | 2,728 | | | $ | 2,854 | | | $ | 1,022 | | | $ | 1,578 | | | $ | 659 | | | $ | 936 | | | $ | 438 | | | $ | 15,556 | |
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| | 2019 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail Electric | | $ | 4,789 | | | $ | 1,938 | | | $ | 2,740 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 9,465 | |
Retail Gas | | — | | | 570 | | | 116 | | | — | | | — | | | — | | | — | | | — | | | 686 | |
Wholesale | | 99 | | | 309 | | | 51 | | | — | | | — | | | — | | | — | | | (2) | | | 457 | |
Transmission and distribution | | 98 | | | 57 | | | 98 | | | 876 | | | — | | | 690 | | | — | | | — | | | 1,819 | |
Interstate pipeline | | — | | | — | | | — | | | — | | | 1,122 | | | — | | | — | | | (118) | | | 1,004 | |
Other | | — | | | — | | | 2 | | | — | | | — | | | — | | | — | | | — | | | 2 | |
Total Regulated | | 4,986 | | | 2,874 | | | 3,007 | | | 876 | | | 1,122 | | | 690 | | | — | | | (122) | | | 13,433 | |
Nonregulated | | — | | | 30 | | | — | | | 36 | | | — | | | 17 | | | 744 | | | 577 | | | 1,404 | |
Total Customer Revenue | | 4,986 | | | 2,904 | | | 3,007 | | | 912 | | | 1,122 | | | 707 | | | 744 | | | 455 | | | 14,837 | |
Other revenue | | 82 | | | 23 | | | 30 | | | 101 | | | 9 | | | — | | | 188 | | | 101 | | | 534 | |
Total | | $ | 5,068 | | | $ | 2,927 | | | $ | 3,037 | | | $ | 1,013 | | | $ | 1,131 | | | $ | 707 | | | $ | 932 | | | $ | 556 | | | $ | 15,371 | |
(1)The BHE and Other reportable segment represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| HomeServices |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Brokerage | $ | 5,498 | | | $ | 4,520 | | | $ | 4,028 | |
Franchise | 85 | | | 76 | | | 68 | |
Total Customer Revenue | 5,583 | | | 4,596 | | | 4,096 | |
Mortgage and other revenue | 632 | | | 800 | | | 377 | |
Total | $ | 6,215 | | | $ | 5,396 | | | $ | 4,473 | |
Remaining Performance Obligations
The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2021, by reportable segment (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
BHE Pipeline Group | $ | 2,607 | | | $ | 21,038 | | | $ | 23,645 | |
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(18)BHE Shareholders' Equity
Preferred Stock
As of December 31, 2021 and 2020, BHE had 1,649,988 and 3,750,000 shares outstanding of its Perpetual Preferred Stock (the "4% Perpetual Preferred Stock") issued to certain subsidiaries of Berkshire Hathaway Inc. The 4% Perpetual Preferred Stock has a liquidation preference of $1,000 per share and currently pays a 4.00% dividend per share on the liquidation preference. Dividends shall accrue and accumulate daily, be cumulative, compound semi-annually and, if declared, be payable in cash semi-annually in arrears on May 15 and November 15 of each year. If dividends are not declared and paid, any accumulating dividends shall continue to accumulate and compound. BHE may not make any dividends on shares of any other class or series of its capital stock (other than for dividends on shares of common stock payable in shares of common stock, unless the holders of the then outstanding 4% Perpetual Preferred Stock shall first receive, or simultaneously receive, a dividend in an amount at least equivalent to the amount accumulated and not previously paid. BHE may not declare or pay any dividends on shares of the 4% Perpetual Preferred Stock if such declaration or payment would constitute an event of default on BHE's senior indebtedness (as defined). BHE may, at its option, redeem the 4% Perpetual Preferred Stock in whole or in part at any time at a price per share equal to the liquidation preference.
Common Stock
On March 14, 2000, and as amended on December 7, 2005, BHE's shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these licenses.rights allows certain shareholders the ability to put their common shares to BHE at the then-current fair value dependent on certain circumstances controlled by BHE.
Restricted Net Assets
BHE has maximum debt-to-total capitalization percentage restrictions imposed by its senior unsecured credit facilities expiring in June 2024 which, in certain circumstances, limit BHE's ability to make cash dividends or distributions. As a result of this restriction, BHE has restricted net assets of $18.3 billion as of December 31, 2021.
Certain of BHE's subsidiaries have restrictions on their ability to dividend, loan or advance funds to BHE due to specific legal or regulatory restrictions, including, but not limited to, maximum debt-to-total capitalization percentages and commitments made to state commissions. As a result of these restrictions, BHE's subsidiaries had restricted net assets of $20.3 billion as of December 31, 2021.
(19)Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
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| | Unrecognized | | Foreign | | | | Unrealized | | | | AOCI |
| | Amounts on | | Currency | | | | Gains (Losses) | | | | Attributable |
| | Retirement | | Translation | | | | on Cash Flow | | Noncontrolling | | To BHE |
| | Benefits | | Adjustment | | | | Hedges | | Interests | | Shareholders, Net |
| | | | | | | | | | | | |
Balance, December 31, 2018 | | $ | (358) | | | $ | (1,623) | | | | | $ | 36 | | | $ | — | | | $ | (1,945) | |
Other comprehensive (loss) income | | (59) | | | 327 | | | | | (29) | | | — | | | 239 | |
Balance, December 31, 2019 | | (417) | | | (1,296) | | | | | 7 | | | — | | | (1,706) | |
Other comprehensive (loss) income | | (65) | | | 234 | | | | | (15) | | | — | | | 154 | |
BHE GT&S acquisition | | (10) | | | — | | | | | — | | | 10 | | | — | |
Balance, December 31, 2020 | | (492) | | | (1,062) | | | | | (8) | | | 10 | | | (1,552) | |
Other comprehensive income (loss) | | 174 | | | (24) | | | | | 67 | | | (5) | | | 212 | |
Balance, December 31, 2021 | | $ | (318) | | | $ | (1,086) | | | | | $ | 59 | | | $ | 5 | | | $ | (1,340) | |
Reclassifications from AOCI to net income for the years ended December 31, 2021, 2020 and 2019 were insignificant. Additionally, refer to the "Foreign Operations" discussion in Note 13 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.
(20)Variable Interest Entities and Noncontrolling Interests
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As part of the GT&S Transaction, BHE acquired an indirect 25% economic interest in Cove Point, consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. BHE is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Included in noncontrolling interests on the Consolidated Balance Sheets are (i) Dominion Energy's 50% interest in Cove Point and Brookfield Super-Core Infrastructure Partner's 25% interest in Cove Point and (ii) preferred securities of subsidiaries of $58 million as of December 31, 2021 and 2020, consisting of $56 million of 8.061% cumulative preferred securities of Northern Electric plc, a subsidiary of Northern Powergrid, which are redeemable in the event of the revocation of Northern Electric plc's electricity distribution license by the Secretary of State, and $2 million of nonredeemable preferred stock of PacifiCorp.
(21)Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 1,096 | | | $ | 1,290 | |
Restricted cash and cash equivalents | 127 | | | 140 | |
Investments and restricted cash and cash equivalents and investments | 21 | | | 15 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 1,244 | | | $ | 1,445 | |
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 2,041 | | | $ | 1,855 | | | $ | 1,723 | |
Income taxes received, net(1) | $ | 1,309 | | | $ | 1,361 | | | $ | 850 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 834 | | | $ | 801 | | | $ | 888 | |
| | | | | |
(1)Includes $1,441 million, $1,504 million and $942 million of income taxes received from Berkshire Hathaway in 2021, 2020 and 2019, respectively.
(22)Segment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
PacifiCorp | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
MidAmerican Funding | 3,547 | | | 2,728 | | | 2,927 | |
NV Energy | 3,107 | | | 2,854 | | | 3,037 | |
Northern Powergrid | 1,188 | | | 1,022 | | | 1,013 | |
BHE Pipeline Group | 3,544 | | | 1,578 | | | 1,131 | |
BHE Transmission | 731 | | | 659 | | | 707 | |
BHE Renewables | 981 | | | 936 | | | 932 | |
HomeServices | 6,215 | | | 5,396 | | | 4,473 | |
BHE and Other(1) | 541 | | | 438 | | | 556 | |
Total operating revenue | $ | 25,150 | | | $ | 20,952 | | | $ | 19,844 | |
| | | | | |
Depreciation and amortization: | | | | | |
PacifiCorp | $ | 1,088 | | | $ | 1,209 | | | $ | 954 | |
MidAmerican Funding | 914 | | | 716 | | | 638 | |
NV Energy | 549 | | | 502 | | | 482 | |
Northern Powergrid | 305 | | | 266 | | | 254 | |
BHE Pipeline Group | 492 | | | 231 | | | 115 | |
BHE Transmission | 238 | | | 201 | | | 240 | |
BHE Renewables | 241 | | | 284 | | | 282 | |
HomeServices | 52 | | | 45 | | | 47 | |
BHE and Other(1) | 2 | | | 1 | | | (1) | |
Total depreciation and amortization | $ | 3,881 | | | $ | 3,455 | | | $ | 3,011 | |
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| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating income: | | | | | |
PacifiCorp | $ | 1,133 | | | $ | 924 | | | $ | 1,072 | |
MidAmerican Funding | 416 | | | 454 | | | 549 | |
NV Energy | 621 | | | 649 | | | 655 | |
Northern Powergrid | 543 | | | 421 | | | 472 | |
BHE Pipeline Group | 1,516 | | | 779 | | | 572 | |
BHE Transmission | 339 | | | 316 | | | 323 | |
BHE Renewables | 329 | | | 291 | | | 336 | |
HomeServices | 505 | | | 511 | | | 222 | |
BHE and Other(1) | (75) | | | (54) | | | (51) | |
Total operating income | 5,327 | | | 4,291 | | | 4,150 | |
Interest expense | (2,118) | | | (2,021) | | | (1,912) | |
Capitalized interest | 64 | | | 80 | | | 77 | |
Allowance for equity funds | 126 | | | 165 | | | 173 | |
Interest and dividend income | 89 | | | 71 | | | 117 | |
Gains (losses) on marketable securities, net | 1,823 | | | 4,797 | | | (288) | |
Other, net | (17) | | | 88 | | | 97 | |
Total income before income tax (benefit) expense and equity loss | $ | 5,294 | | | $ | 7,471 | | | $ | 2,414 | |
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| |
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Interest expense: | | | | | |
PacifiCorp | $ | 430 | | | $ | 426 | | | $ | 401 | |
MidAmerican Funding | 319 | | | 322 | | | 302 | |
NV Energy | 206 | | | 227 | | | 229 | |
Northern Powergrid | 130 | | | 130 | | | 139 | |
BHE Pipeline Group | 143 | | | 74 | | | 52 | |
BHE Transmission | 155 | | | 148 | | | 157 | |
BHE Renewables | 158 | | | 166 | | | 174 | |
HomeServices | 4 | | | 11 | | | 25 | |
BHE and Other(1) | 573 | | | 517 | | | 433 | |
Total interest expense | $ | 2,118 | | | $ | 2,021 | | | $ | 1,912 | |
| | | | | |
Income tax (benefit) expense: | | | | | |
PacifiCorp | $ | (78) | | | $ | (75) | | | $ | 61 | |
MidAmerican Funding | (680) | | | (574) | | | (377) | |
NV Energy | 56 | | | 61 | | | 98 | |
Northern Powergrid | 192 | | | 96 | | | 59 | |
BHE Pipeline Group | 269 | | | 162 | | | 138 | |
BHE Transmission | 10 | | | 13 | | | 11 | |
BHE Renewables(2) | (753) | | | (602) | | | (325) | |
HomeServices | 138 | | | 138 | | | 51 | |
BHE and Other(1) | (286) | | | 1,089 | | | (314) | |
Total income tax (benefit) expense | $ | (1,132) | | | $ | 308 | | | $ | (598) | |
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| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Earnings on common shares: | | | | | |
PacifiCorp | $ | 889 | | | $ | 741 | | | $ | 773 | |
MidAmerican Funding | 883 | | | 818 | | | 781 | |
NV Energy | 439 | | | 410 | | | 365 | |
Northern Powergrid | 247 | | | 201 | | | 256 | |
BHE Pipeline Group | 807 | | | 528 | | | 422 | |
BHE Transmission | 247 | | | 231 | | | 229 | |
BHE Renewables(2) | 451 | | | 521 | | | 431 | |
HomeServices | 387 | | | 375 | | | 160 | |
BHE and Other(1) | 1,319 | | | 3,092 | | | (467) | |
Total earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | 2,950 | |
| | | | | |
Capital expenditures: | | | | | |
PacifiCorp | $ | 1,513 | | | $ | 2,540 | | | $ | 2,175 | |
MidAmerican Funding | 1,912 | | | 1,836 | | | 2,810 | |
NV Energy | 749 | | | 675 | | | 657 | |
Northern Powergrid | 742 | | | 682 | | | 602 | |
BHE Pipeline Group | 1,128 | | | 659 | | | 687 | |
BHE Transmission | 279 | | | 372 | | | 247 | |
BHE Renewables | 225 | | | 95 | | | 122 | |
HomeServices | 42 | | | 36 | | | 54 | |
BHE and Other | 21 | | | (130) | | | 10 | |
Total capital expenditures | $ | 6,611 | | | $ | 6,765 | | | $ | 7,364 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Property, plant and equipment, net: | | | | | |
PacifiCorp | $ | 22,914 | | | $ | 22,430 | | | $ | 20,973 | |
MidAmerican Funding | 20,302 | | | 19,279 | | | 18,377 | |
NV Energy | 10,231 | | | 9,865 | | | 9,613 | |
Northern Powergrid | 7,572 | | | 7,230 | | | 6,606 | |
BHE Pipeline Group | 15,692 | | | 15,097 | | | 5,482 | |
BHE Transmission | 6,590 | | | 6,445 | | | 6,157 | |
BHE Renewables | 6,103 | | | 5,645 | | | 5,976 | |
HomeServices | 169 | | | 159 | | | 161 | |
BHE and Other | 243 | | | (22) | | | (40) | |
Total property, plant and equipment, net | $ | 89,816 | | | $ | 86,128 | | | $ | 73,305 | |
| | | | | |
Total assets: | | | | | |
PacifiCorp | $ | 27,615 | | | $ | 26,862 | | | $ | 24,861 | |
MidAmerican Funding | 25,352 | | | 23,530 | | | 22,664 | |
NV Energy | 15,239 | | | 14,501 | | | 14,128 | |
Northern Powergrid | 9,326 | | | 8,782 | | | 8,385 | |
BHE Pipeline Group | 20,434 | | | 19,541 | | | 6,100 | |
BHE Transmission | 9,476 | | | 9,208 | | | 8,776 | |
BHE Renewables | 11,829 | | | 12,004 | | | 9,961 | |
HomeServices | 4,574 | | | 4,955 | | | 3,846 | |
BHE and Other | 8,220 | | | 7,933 | | | 1,330 | |
Total assets | $ | 132,065 | | | $ | 127,316 | | | $ | 100,051 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue by country: | | | | | |
United States | $ | 23,215 | | | $ | 19,254 | | | $ | 18,108 | |
United Kingdom | 1,188 | | | 1,022 | | | 1,011 | |
Canada | 719 | | | 653 | | | 706 | |
Other | 28 | | | 23 | | | 19 | |
Total operating revenue by country | $ | 25,150 | | | $ | 20,952 | | | $ | 19,844 | |
| | | | | |
Income before income tax (benefit) expense and equity loss by country: | | | | |
United States | $ | 4,650 | | | $ | 6,954 | | | $ | 1,866 | |
United Kingdom | 454 | | | 338 | | | 326 | |
Canada | 181 | | | 173 | | | 178 | |
Other | 9 | | | 6 | | | 44 | |
Total income before income tax (benefit) expense and equity loss by country: | $ | 5,294 | | | $ | 7,471 | | | $ | 2,414 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Property, plant and equipment, net by country: | | | | | |
United States | $ | 75,774 | | | $ | 72,583 | | | $ | 60,634 | |
United Kingdom | 7,487 | | | 7,134 | | | 6,504 | |
Canada | 6,547 | | | 6,401 | | | 6,157 | |
Other | 8 | | | 10 | | | 10 | |
Total property, plant and equipment, net by country | $ | 89,816 | | | $ | 86,128 | | | $ | 73,305 | |
(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate to other corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
(2)Income tax (benefit) expense includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2021 and 2020 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE | | | | | | | | | | |
| | | MidAmerican | | NV | | Northern | | Pipeline | | BHE | | BHE | | | | | | |
| PacifiCorp | | Funding | | Energy | | Powergrid | | Group | | Transmission | | Renewables | | HomeServices | | | | Total |
| | | | | | | | | | | | | | | | | | | |
December 31, 2019 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 978 | | | $ | 73 | | | $ | 1,520 | | | $ | 95 | | | $ | 1,456 | | | | | $ | 9,722 | |
Acquisitions | — | | | — | | | — | | | — | | | 1,730 | | | — | | | — | | | 1 | | | | | 1,731 | |
Foreign currency translation | — | | | — | | | — | | | 22 | | | — | | | 31 | | | — | | | — | | | | | 53 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
December 31, 2020 | 1,129 | | | 2,102 | | | 2,369 | | | 1,000 | | | 1,803 | | | 1,551 | | | 95 | | | 1,457 | | | | | 11,506 | |
Acquisitions | — | | | — | | | — | | | — | | | 11 | | | — | | | — | | | 129 | | | | | 140 | |
Foreign currency translation | — | | | — | | | — | | | (8) | | | — | | | 12 | | | — | | | — | | | | | 4 | |
| | | | | | | | | | | | | | | | | | | |
December 31, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 992 | | | $ | 1,814 | | | $ | 1,563 | | | $ | 95 | | | $ | 1,586 | | | | | $ | 11,650 | |
PacifiCorp and its subsidiaries
Consolidated Financial Section
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with PacifiCorp's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2021, was $888 million, an increase of $149 million, or 20%, compared to 2020, primarily due to higher utility gross margin (excluding $231 million of decreases fully offset in depreciation, operating, other income/expense and income tax expense due to prior year regulatory adjustments); lower operations and maintenance expense primarily due to prior year costs associated with the 2020 Wildfires and changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met; and favorable income tax expense from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking; partially offset by higher depreciation and amortization expense (excluding $376 million of decreases offset in operating revenue and income tax expense due to prior year regulatory adjustments) from the impacts of the depreciation study for which rates became effective January 2021 and higher plant in-service; and lower allowances for equity and borrowed funds used during construction. Utility margin increased $145 million (excluding the $231 million of fully offsetting decreases) primarily due to the higher retail, wheeling and wholesale revenue; higher deferred net power costs; and lower purchased electricity volumes; partially offset by higher purchased electricity prices; and higher natural gas- and coal-fueled generation costs. Retail customer volumes increased 3.1% due to increase in customer usage, increase in the average number of customers and favorable impacts of weather. Energy generated increased 10% for 2021 compared to 2020 primarily due higher wind-powered, natural gas-fueled and coal-fueled generation, partially offset by lower hydroelectric-powered generation. Wholesale electricity sales volumes decreased 3% and purchased electricity volumes decreased 17%.
Net income for the year ended December 31, 2020 was $739 million, a decrease of $32 million, or 4%, compared to 2019, primarily due to costs associated with the 2020 Wildfires and the Klamath Hydroelectric Project of $169 million; higher net interest expense of $36 million from higher long-term debt and lower cash balances; higher pension and other postretirement costs of $13 million; and higher property taxes of $10 million; partially offset by lower income tax expense of $99 million (excluding $37 million fully offset primarily in depreciation expense) primarily driven by higher PTCs substantially due to repowered wind-powered generating facilities and lower pre-tax income; higher utility margin of $47 million (excluding $231 million of increases fully offset in depreciation, operating, other income/expense and income tax expense as a result of regulatory adjustments as ordered by the UPSC, the OPUC and the IPUC); higher allowances for equity and borrowed funds used during construction of $38 million; and prior year costs associated with the early retirement of a coal-fueled generation unit totaling $24 million. Utility margin increased primarily due to lower coal-fueled generation volumes, lower purchased electricity prices, higher average retail rates and lower natural gas-fueled generation costs, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower retail customer volumes and higher purchased electricity volumes. Retail customer volumes decreased 1.4% primarily due to impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of residential and commercial customers and the favorable impact of weather. Energy generated decreased 4% for 2020 compared to 2019 primarily due to lower coal-fueled generation, partially offset by higher wind and hydroelectric-powered generation. Wholesale electricity sales volumes decreased 4% and purchased electricity volumes increased 9%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
PacifiCorp's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in PacifiCorp's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin: | | | | | | | | | | | | | |
Operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | 5 | % |
Cost of fuel and energy | 1,831 | | | 1,790 | | | 41 | | 2 | | | 1,790 | | | 1,795 | | | (5) | | — | |
Utility margin | 3,465 | | | 3,551 | | | (86) | | (2) | | | 3,551 | | | 3,273 | | | 278 | | 8 | |
Operations and maintenance | 1,031 | | | 1,209 | | | (178) | | (15) | | | 1,209 | | | 1,048 | | | 161 | | 15 | |
Depreciation and amortization | 1,088 | | | 1,209 | | | (121) | | (10) | | | 1,209 | | | 954 | | | 255 | | 27 | |
Property and other taxes | 213 | | | 209 | | | 4 | | 2 | | | 209 | | | 199 | | | 10 | | 5 | |
Operating income | $ | 1,133 | | | $ | 924 | | | $ | 209 | | 23 | % | | $ | 924 | | | $ | 1,072 | | | $ | (148) | | (14) | % |
Utility Margin
A comparison of key operating results related to utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
| | | | | | | | | | | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | | | |
Operating revenue | | $ | 5,296 | | | $ | 5,341 | | | $ | (45) | | | (1) | % | | $ | 5,341 | | | $ | 5,068 | | | $ | 273 | | | 5 | % |
Cost of fuel and energy | | 1,831 | | | 1,790 | | | 41 | | | 2 | | | 1,790 | | | 1,795 | | | (5) | | | — | |
Utility margin | | $ | 3,465 | | | $ | 3,551 | | | $ | (86) | | | (2) | % | | $ | 3,551 | | | $ | 3,273 | | | $ | 278 | | | 8 | % |
| | | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | | |
Residential | | 17,905 | | | 17,150 | | | 755 | | | 4 | % | | 17,150 | | | 16,668 | | | 482 | | | 3 | % |
Commercial(1) | | 18,839 | | | 17,727 | | | 1,112 | | | 6 | | | 17,727 | | | 18,151 | | | (424) | | | (2) | |
Industrial(1) | | 17,909 | | | 18,039 | | | (130) | | | (1) | | | 18,039 | | | 19,049 | | | (1,010) | | | (5) | |
Other(1) | | 1,621 | | | 1,644 | | | (23) | | | (1) | | | 1,644 | | | 1,475 | | | 169 | | | 11 | |
Total retail | | 56,274 | | | 54,560 | | | 1,714 | | | 3 | | | 54,560 | | | 55,343 | | | (783) | | | (1) | |
Wholesale | | 5,113 | | | 5,249 | | | (136) | | | (3) | | | 5,249 | | | 5,480 | | | (231) | | | (4) | |
Total sales | | 61,387 | | | 59,809 | | | 1,578 | | | 3 | % | | 59,809 | | | 60,823 | | | (1,014) | | | (2) | % |
| | | | | | | | | | | | | | | | |
Average number of retail customers | | | | | | | | | | | | | | | | |
(in thousands) | | 2,003 | | | 1,967 | | | 36 | | | 2 | % | | 1,967 | | | 1,933 | | | 34 | | | 2 | % |
| | | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | | |
Retail | | $ | 86.08 | | | $ | 90.59 | | | $ | (4.51) | | | (5) | % | | $ | 90.59 | | | $ | 84.80 | | | $ | 5.79 | | | 7 | % |
Wholesale | | $ | 37.90 | | | $ | 35.56 | | | $ | 2.34 | | | 7 | % | | $ | 35.56 | | | $ | 35.21 | | | $ | 0.35 | | | 1 | % |
| | | | | | | | | | | | | | | | |
Heating degree days | | 9,914 | | | 10,155 | | | (241) | | | (2) | % | | 10,155 | | | 11,143 | | | (988) | | | (9) | % |
Cooling degree days | | 2,431 | | | 2,111 | | | 320 | | | 15 | % | | 2,111 | | | 1,773 | | | 338 | | | 19 | % |
| | | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | | |
Coal | | 31,566 | | | 30,636 | | | 930 | | | 3 | % | | 30,636 | | | 34,510 | | | (3,874) | | | (11) | % |
Natural gas | | 13,323 | | | 12,045 | | | 1,278 | | | 11 | | | 12,045 | | | 12,058 | | | (13) | | | — | |
Wind(2) | | 6,686 | | | 3,769 | | | 2,917 | | | 77 | | | 3,769 | | | 2,266 | | | 1,503 | | | 66 | |
Hydroelectric and other(2) | | 3,010 | | | 3,223 | | | (213) | | | (7) | | | 3,223 | | | 2,961 | | | 262 | | | 9 | |
Total energy generated | | 54,585 | | | 49,673 | | | 4,912 | | | 10 | | | 49,673 | | | 51,795 | | | (2,122) | | | (4) | |
Energy purchased | | 11,601 | | | 14,054 | | | (2,453) | | | (17) | | | 14,054 | | | 12,906 | | | 1,148 | | | 9 | |
Total | | 66,186 | | | 63,727 | | | 2,459 | | | 4 | % | | 63,727 | | | 64,701 | | | (974) | | | (2) | % |
| | | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | | |
Energy generated(3) | | $ | 18.05 | | | $ | 18.74 | | | $ | (0.69) | | | (4) | % | | $ | 18.74 | | | $ | 19.36 | | | $ | (0.62) | | | (3) | % |
Energy purchased | | $ | 66.93 | | | $ | 47.60 | | | $ | 19.33 | | | 41 | % | | $ | 47.60 | | | $ | 54.20 | | | $ | (6.60) | | | (12) | % |
(1) GWh amounts are net of energy used by the related generating facilities.
(2)All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Utility margin decreased $86 million (including the $231 million of fully offsetting decreases) for 2021 compared to 2020 primarily due to:
•$111 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;
•$99 million of lower retail revenue primarily due to $234 million fully offset in depreciation expense, income tax expense, fuel expense, and other income (expense) due to accelerated depreciation of certain coal-fueled units in Utah and Oregon and recognition of certain Utah regulatory balances in the prior year, and lower average retail prices, partially offset by higher retail customer volumes. Retail customer volumes increased 3.1% due to an increase in residential and commercial customer usage, increase in the average number of customers and favorable impacts of weather, primarily in Oregon, Washington and Idaho;
•$88 million of higher natural gas-fueled generation costs primarily due to higher average prices and higher volumes; and
•$34 million of lower other revenue due to prior year recognition of prior OATT revenue related deferrals in Oregon used to accelerate the depreciation of certain retired wind equipment as a result of the 2020 Oregon RAC settlement (offset in depreciation expense).
The decreases above were partially offset by:
•$141 million primarily from higher deferred net power costs in accordance with established adjustment mechanisms;
•$43 million of favorable wheeling activities;
•$33 million of lower coal-fueled generation costs primarily due to $37 million of accelerated recognition of certain Utah regulatory balances associated with the 2015 Utah mine disposition and certain Cholla Unit 4 related closure costs in Oregon and Idaho (offset in income tax expense) in the prior year and lower prices, partially offset by higher volumes;
•$19 million of higher other revenue primarily due to higher REC, fly ash and by-product revenues; and
•$7 million of higher wholesale revenue due to higher average wholesale market prices, partially offset by lower wholesale volumes.
Operations and maintenance decreased $178 million, or 15%, for 2021 compared to 2020 primarily due to prior year estimated losses associated with the 2020 Wildfires of $136 million, net of expected insurance recoveries, changes in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met, lower thermal plant maintenance expense and lower labor expenses, partially offset by higher wind plant and distribution maintenance and higher legal and insurance expenses associated with the 2020 Wildfires.
Depreciation and amortization decreased $121 million, or 10%, for 2021 compared to 2020 primarily due to prior year accelerated depreciation of $376 million as a result of regulatory adjustments ordered by the UPSC, the OPUC and the IPUC (fully offset in retail revenue, other revenue, and income tax expense), including accelerated depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment as a result the 2020 Oregon RAC settlement, partially offset by the impacts of the depreciation study for which rates became effective January 1, 2021 of approximately $158 million and higher plant in-service balances.
Property and other taxes increased $4 million, or 2%, for 2021 compared to 2020 primarily due to higher property taxes in Oregon and Wyoming, partially offset by lower property taxes in Utah and Washington.
Interest expense increased $4 million, or 1%, for 2021 compared to 2020 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds decreased $72 million, or 49%, for 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.
Interest and dividend income increased$14 million, or 140%, for 2021 compared to 2020 primarily due to higher carrying charges on DSM regulatory assets in the current year.
Income tax benefit increased $4 million, or 5%, for 2021 compared to 2020. The effective tax rate was (10)% and (11)% for 2021 and 2020, respectively. The effective tax rate increased primarily as a result of lower effects of ratemaking associated with excess deferred income tax amortization, offset by increased PTCs from PacifiCorp's new wind-powered generating facilities in the current year. In 2020, $118 million of excess deferred income taxes was amortized pursuant to regulatory orders from Utah, Oregon and Idaho, whereby portions of excess deferred income taxes were used to accelerate depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment or offset other regulatory balances for these jurisdictions.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Utility margin increased $278 million for 2020 compared to 2019 primarily due to:
•$249 million increase in retail revenue, including $234 million fully offset in depreciation expense and income tax expense due to accelerated depreciation of certain coal-fueled units in Utah and Oregon and recognition of certain Utah regulatory balances and higher average retail prices, partially offset by lower retail customer volumes. Retail customer volumes decreased 1.4% primarily due to impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of residential and commercial customers and the favorable impact of weather;
•$49 million of lower coal-fueled generation costs primarily due to lower volumes of $78 million, partially offset by $37 million of accelerated recognition of certain Utah regulatory balances associated with the 2015 Utah mine disposition and certain Cholla Unit 4 related closure costs in Oregon and Idaho (offset in income tax expense) and higher prices of $9 million;
•$34 million of higher other revenue due to recognition of prior OATT revenue related deferrals in Oregon used to accelerate the depreciation of certain retired wind equipment as a result of the 2020 Oregon RAC settlement (offset in depreciation expense);
•$31 million of lower purchased electricity costs, primarily due to lower average market prices, partially offset by higher volumes; and
•$24 million of lower natural gas-fueled generation costs primarily due to lower average prices and lower volumes.
The increases above were partially offset by:
•$106 million primarily from lower deferrals and higher amortization of previous deferrals of incurred net power costs in accordance with established adjustment mechanisms.
Operations and maintenance increased $161 million, or 15%, for 2020 compared to 2019 primarily due to costs associated with the 2020 Wildfires of $136 million, net of expected insurance recoveries, and costs associated with the Klamath Hydroelectric Project of $33 million, higher vegetation management and wildfire mitigation costs of $26 million and increased bad debt expense of $5 million, partially offset by prior year costs associated with the early retirement of Cholla Unit 4 of $24 million and lower employee related expenses of $7 million as a result of COVID-19.
Depreciation and amortization increased $255 million, or 27%, for 2020 compared to 2019 primarily due to current year accelerated depreciation of $376 million as a result of regulatory adjustments ordered by the UPSC, the OPUC and the IPUC (fully offset in retail revenue, other revenue, and income tax expense), including accelerated depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment as a result the 2020 Oregon RAC settlement, partially offset by prior year accelerated depreciation of $120 million (offset in income tax expense) on Oregon's share of certain retired wind equipment due to repowering as a result of the 2019 Oregon RAC settlement.
Property and other taxes increased $10 million, or 5%, for 2020 compared to 2019 primarily due to higher property taxes in Oregon and Utah.
Interest expense increased $25 million, or 6%, for 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds increased $38 million, or 35%, for 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income decreased $11 million, or 52%, for 2020 compared to 2019 primarily due to lower average interest rates in the current year.
Other, net decreased $22 million, or 69% for 2020 compared to 2019 primarily due to higher pension and post retirement costs of $13 million and costs associated with the recognition of Utah's share of the post retirement settlement loss associated with the 2015 Utah mine disposition (offset in income tax expense).
Income tax (benefit) expense decreased $136 million to a benefit of $75 million for 2020 compared to an expense of $61 million for 2019. The effective tax rate was (11)% and 7% for 2020 and 2019, respectively. The effective tax rate decreased primarily as a result of higher amortization of excess deferred income taxes in 2020 and higher PTCs. In 2020, $118 million of excess deferred income taxes was amortized pursuant to regulatory orders from Utah, Oregon and Idaho, whereby portions of excess deferred income taxes were used to accelerate depreciation of certain coal-fueled units and Oregon's share of certain retired wind equipment or offset other regulatory balances for these jurisdictions. In 2019, $91 million of Oregon's allocated excess deferred income taxes was amortized pursuant to the 2019 Oregon RAC proceeding, whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment due to repowering.
Liquidity and Capital Resources
As of December 31, 2021, PacifiCorp's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 179 | |
| | |
Credit facilities(1) | | 1,200 | |
Less: | | |
| | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | 982 | |
| | |
Total net liquidity | | $ | 1,161 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding PacifiCorp's credit facilities.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $1.8 billion and $1.6 billion, respectively. The increase is primarily due to higher cash received for income taxes and higher collections from retail customers, partially offset by higher wholesale purchases and timing of operating payables.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $1.6 billion and $1.5 billion, respectively. The increase is primarily due to lower purchased power prices, lower cash paid for income taxes and lower operating expense payments due to timing, partially offset by lower collections from wholesale and retail customers and higher fuel expense payments due to timing.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(1.5) billion and $(2.5) billion, respectively. The decrease in net cash outflows from investing activities is mainly due to a decrease in capital expenditures of $1.0 billion.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $(2.5) billion and $(2.2) billion, respectively. The increase in net cash outflows from investing activities is mainly due to an increase in capital expenditures of $365 million, partially offset by proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015.
Financing Activities
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31, 2021, PacifiCorp had no short-term debt outstanding. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%. For further discussion, refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Long-term Debt
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.
PacifiCorp made repayments on long-term debt totaling $870 million and $38 million during the years ended December 31, 2021 and 2020, respectively.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2021, PacifiCorp estimated it would be able to issue up to $11.8 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances are subject to market conditions and amounts are further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
Credit Facilities
In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.
In 2020, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations decreased by $38 million due to maturities.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.
Preferred Stock
As of December 31, 2021 and 2020, PacifiCorp had non-redeemable preferred stock outstanding with an aggregate stated value of $2 million.
Common Shareholder's Equity
In 2021 and 2020, PacifiCorp declared and paid dividends of $150 million and $— million, respectively, to PPW Holdings LLC.
Capitalization
PacifiCorp manages its capitalization and liquidity position to maintain a prudent capital structure with an objective of retaining strong investment grade credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, customers and creditors and provide a competitive cost of capital and predictable capital market access.
Under existing or prospective authoritative accounting guidance, such as guidance pertaining to consolidations and leases, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as lease obligations on PacifiCorp's financial statements. While PacifiCorp has successfully amended covenants in financing arrangements that may be impacted, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers under financing agreements and from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its indirect parent company, BHE, or take other actions.
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Wind generation | $ | 933 | | | $ | 1,277 | | | $ | 131 | | | $ | 210 | | | $ | 473 | | | $ | 440 | |
Electric distribution | 413 | | | 613 | | | 618 | | | 610 | | | 586 | | | 515 | |
Electric transmission | 612 | | | 405 | | | 315 | | | 927 | | | 1,617 | | | 836 | |
Other | 217 | | | 245 | | | 449 | | | 254 | | | 641 | | | 710 | |
Total | $ | 2,175 | | | $ | 2,540 | | | $ | 1,513 | | | $ | 2,001 | | | $ | 3,317 | | | $ | 2,501 | |
PacifiCorp's 2019 and 2021 IRPs identified a roadmap for a significant increase in renewable and carbon free generation resources, coal to natural gas conversion of certain coal-fueled units, energy storage and associated transmission. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
•Wind generation includes both growth projects and operating expenditures. Growth projects include:
◦Construction of wind-powered generating facilities at PacifiCorp totaled $107 million for 2021, $1,148 million for 2020 and $338 million for 2019. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $131 million in 2022, $405 million in 2023 and $373 million in 2024.
◦Repowering of existing wind-powered generating facilities at PacifiCorp totaled $9 million in 2021, $125 million in 2020 and $585 million in 2019. All existing wind-powered generating facilities at PacifiCorp have been repowered as of December 31, 2021.
◦The 2021 IRP also included PacifiCorp's planned acquisition and repowering of two wind-powered generating facilities. The repowered facilities are expected to be placed in-service in 2023 and 2024. PacifiCorp spent $11 million in 2021 and planned spending for acquiring and repowering generating facilities totals $60 million in 2022, $36 million in 2023 and $34 million in 2024.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $176 million in 2021, $187 million in 2020 and $4 million in 2019, and planned spending totals $153 million in 2022, $133 million in 2023 and $127 million in 2024. Remaining investments relate to expenditures for new connections and distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission investment in 2021 through 2024 primarily reflects planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. PacifiCorp is advancing permitting and regulatory approvals related to the projects. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $565 million in 2022, $1,143 million in 2023, and $437 million in 2024.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $108 million in 2021, $75 million in 2020 and $62 million for 2019. Planned information technology spending totals $167 million in 2022, $163 million in 2023 and $136 million in 2024. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
Off-Balance Sheet Arrangements
PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees or similar arrangements. PacifiCorp currently has indemnification obligations in connection with the sale or transfer of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with authoritative accounting guidance. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. Refer to Notes 11 and 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these obligations and arrangements.
Material Cash Requirements
PacifiCorp has cash requirements that may affect its consolidated financial condition that arise primarily from long-term debt (refer to Note 8), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), cost of removal and AROs (refer to Notes 6 and 11), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
PacifiCorp has cash requirements relating to interest payments of $6.5 billion on long-term debt, including $400 million due in 2022.
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding PacifiCorp's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, PacifiCorp would have been required to post $218 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.
Inflation
PacifiCorp operates under a cost-of-service based rate structure administered by various state commissions and the FERC. Under this rate structure, PacifiCorp is allowed to include prudent costs in its rates, including the impact of inflation. PacifiCorp seeks to minimize the potential impact of inflation on its operations through the use of energy and other cost adjustment clauses and tariff riders, by employing prudent risk management and hedging strategies and entering into contracts with fixed pricing where possible by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by PacifiCorp's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with PacifiCorp's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $1.4 billion and total regulatory liabilities were $2.8 billion as of December 31, 2021. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's regulatory assets and liabilities.
Pension and Other Postretirement Benefits
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans as described in Note 10. PacifiCorp recognizes the funded status of these defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2021, PacifiCorp recognized a net asset totaling $46 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2021, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets and accumulated other comprehensive loss totaled $260 million and $23 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rate and expected long-term rate of return on plan assets. These key assumptions are reviewed annually and modified as appropriate. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about PacifiCorp's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2021.
PacifiCorp chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date with cash flows aligning to the expected timing and amount of plan liabilities. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, PacifiCorp evaluates the investment allocation between return-seeking investment and fixed income securities based on the funded status of the plan and utilizes the asset allocation and return assumptions for each asset class based on forward-looking views of the financial markets and historical performance. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. PacifiCorp regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plan |
| +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | |
Effect on December 31, 2021 Benefit Obligations: | | | | | | | |
Discount rate | $ | (50) | | | $ | 55 | | | $ | (13) | | | $ | 15 | |
| | | | | | | |
Effect on 2021 Periodic Cost: | | | | | | | |
Discount rate | $ | — | | | $ | — | | | $ | 1 | | | $ | (1) | |
Expected rate of return on plan assets | (5) | | | 5 | | | (2) | | | 2 | |
A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and PacifiCorp's funding policy for each plan.
Income Taxes
In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on PacifiCorp's consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's income taxes.
It is probable that PacifiCorp will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers in certain state jurisdictions. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $1.3 billion and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $264 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
PacifiCorp's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. PacifiCorp's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which PacifiCorp transacts. The following discussion addresses the significant market risks associated with PacifiCorp's business activities. PacifiCorp has established guidelines for credit risk management. Refer to Notes 2 and 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's contracts accounted for as derivatives.
PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp's exposure to market and credit risk, the risk management committee recommends, and executive management establishes, policies, limits and approved products, which are reviewed frequently to respond to changing market conditions.
Risk is an inherent part of PacifiCorp's business and activities. PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in PacifiCorp's business. The risk management policy governs energy transactions and is designed for hedging PacifiCorp's existing energy and asset exposures, and to a limited extent, the policy permits arbitrage and trading activities to take advantage of market inefficiencies. The policy also governs the types of transactions authorized for use and establishes guidelines for credit risk management and management information systems required to effectively monitor such transactions. PacifiCorp's risk management policy provides for the use of only those contracts that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions.
Commodity Price Risk
PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as PacifiCorp has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. PacifiCorp does not engage in a material amount of proprietary trading activities. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. PacifiCorp's exposure to commodity price risk is generally limited by its ability to include commodity costs in rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
PacifiCorp measures, monitors and manages the market risk in its electricity and natural gas portfolio in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period. PacifiCorp has a risk management policy that requires increasing volumes of hedge transactions over a three-year position management and hedging horizon to reduce market risk of its electricity and natural gas portfolio.
PacifiCorp maintained compliance with its risk management policy and limit procedures during the year ended December 31, 2021.
The table that follows summarizes PacifiCorp's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $5 million and $24 million as of December 31, 2021 and 2020, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | 53 | | | $ | 104 | | | $ | 2 | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | (17) | | | $ | 5 | | | $ | (39) | |
PacifiCorp's commodity derivative contracts are generally recoverable from customers in rates; therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose PacifiCorp to earnings volatility. As of December 31, 2021 and 2020, a regulatory liability of $53 million and a regulatory asset of $17 million, respectively, was recorded related to the net derivative asset of $53 million and a net derivative liability of $17 million, respectively. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, natural gas or fuel are higher or the level of wholesale electricity sales are lower than what is included in rates, including the impacts of adjustment mechanisms.
Interest Rate Risk
PacifiCorp is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, PacifiCorp's fixed-rate long-term debt does not expose PacifiCorp to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity. PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. The nature and amount of PacifiCorp's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7, 8 and 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of PacifiCorp's short- and long-term debt.
As of December 31, 2021 and 2020, PacifiCorp had short- and long-term variable-rate obligations totaling $218 million and $310 million, respectively that expose PacifiCorp to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to PacifiCorp's variable-rate debt as of December 31, 2021 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on PacifiCorp's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PacifiCorp and subsidiaries ("PacifiCorp") as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of PacifiCorp as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of PacifiCorp's management. Our responsibility is to express an opinion on PacifiCorp's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. PacifiCorp is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of PacifiCorp's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
PacifiCorp is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to rates in the respective service territories where PacifiCorp operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense; and income tax expense (benefit).
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow PacifiCorp an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While PacifiCorp has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit PacifiCorp's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated PacifiCorp's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected PacifiCorp's filings with the Commissions and the filings with the Commissions by intervenors that may impact PacifiCorp's future rates, for any evidence that might contradict management's assertions.
We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
California and Oregon 2020 Wildfires – Contingencies – See Note 14 to the financial statements
Critical Audit Matter Description
PacifiCorp has loss contingencies related to the California and Oregon 2020 wildfires (the "2020 wildfires"). PacifiCorp has recorded estimated liabilities, net of expected insurance recoveries, of $136 million as of December 31, 2021, which represents its best estimate of probable losses, net of expected insurance recoveries, as a result of the 2020 wildfires.
We identified wildfire-related contingencies and the related disclosure as a critical audit matter because of the significant judgments made by management to estimate the losses. This required the application of a high degree of judgment and extensive effort when performing audit procedures to evaluate the reasonableness of management's estimate of the losses and disclosure related to wildfire-related loss contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding its estimate of losses for wildfire-related contingencies and the related disclosure included the following, among others:
•We evaluated management's judgments related to whether a loss was probable and reasonably estimable, reasonably possible, or remote for each individual wildfire by inquiring of management and PacifiCorp's external and internal legal counsel regarding the amounts of probable and reasonably estimable, reasonably possible, and remote losses, including the potential impact of information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire, and external information for any evidence that might contradict management's assertions.
•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management and its external and internal legal counsel.
•We tested the significant assumptions used in determining the estimate, including, but not limited to, information gained through management's and its external and internal legal counsel's ongoing investigations into the causes of each fire.
•We read legal letters from PacifiCorp's external and internal legal counsel regarding information regarding ongoing litigation related to the 2020 wildfires and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated whether PacifiCorp's disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ Deloitte & Touche LLP
Portland, Oregon
February 25, 2022
We have served as PacifiCorp's auditor since 2006.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 179 | | | $ | 13 | |
Trade receivables, net | 725 | | | 703 | |
Other receivables, net | 52 | | | 48 | |
Inventories | 474 | | | 482 | |
Regulatory assets | 65 | | | 116 | |
Prepaid expenses | 79 | | | 79 | |
Other current assets | 147 | | | 82 | |
Total current assets | 1,721 | | | 1,523 | |
| | | |
Property, plant and equipment, net | 22,914 | | | 22,430 | |
Regulatory assets | 1,287 | | | 1,279 | |
Other assets | 534 | | | 470 | |
| | | |
Total assets | $ | 26,456 | | | $ | 25,702 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | |
Current liabilities: | | | |
Accounts payable | $ | 680 | | | $ | 772 | |
Accrued interest | 121 | | | 127 | |
Accrued property, income and other taxes | 78 | | | 80 | |
Accrued employee expenses | 89 | | | 84 | |
Short-term debt | — | | | 93 | |
Current portion of long-term debt | 155 | | | 420 | |
Regulatory liabilities | 118 | | | 115 | |
Other current liabilities | 219 | | | 174 | |
Total current liabilities | 1,460 | | | 1,865 | |
| | | |
Long-term debt | 8,575 | | | 8,192 | |
Regulatory liabilities | 2,650 | | | 2,727 | |
Deferred income taxes | 2,847 | | | 2,627 | |
Other long-term liabilities | 1,011 | | | 1,118 | |
Total liabilities | 16,543 | | | 16,529 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholders' equity: | | | |
Preferred stock | 2 | | | 2 | |
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 4,479 | | | 4,479 | |
Retained earnings | 5,449 | | | 4,711 | |
Accumulated other comprehensive loss, net | (17) | | | (19) | |
Total shareholders' equity | 9,913 | | | 9,173 | |
| | | |
Total liabilities and shareholders' equity | $ | 26,456 | | | $ | 25,702 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 1,831 | | | 1,790 | | | 1,795 | |
Operations and maintenance | 1,031 | | | 1,209 | | | 1,048 | |
Depreciation and amortization | 1,088 | | | 1,209 | | | 954 | |
Property and other taxes | 213 | | | 209 | | | 199 | |
Total operating expenses | 4,163 | | | 4,417 | | | 3,996 | |
| | | | | |
Operating income | 1,133 | | | 924 | | | 1,072 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (430) | | | (426) | | | (401) | |
Allowance for borrowed funds | 24 | | | 48 | | | 36 | |
Allowance for equity funds | 50 | | | 98 | | | 72 | |
Interest and dividend income | 24 | | | 10 | | | 21 | |
Other, net | 8 | | | 10 | | | 32 | |
Total other expense | (324) | | | (260) | | | (240) | |
| | | | | |
Income before income tax (benefit) expense | 809 | | | 664 | | | 832 | |
Income tax (benefit) expense | (79) | | | (75) | | | 61 | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
| | | | | |
Other comprehensive income (loss), net of tax — | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $1, $(1) and $(1) | 2 | | | (3) | | | (3) | |
| | | | | |
Comprehensive income | $ | 890 | | | $ | 736 | | | $ | 768 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated | | |
| | | | | Additional | | | | Other | | Total |
| Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2018 | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 3,377 | | | $ | (13) | | | $ | 7,845 | |
Net income | — | | | — | | | — | | | 771 | | | — | | | 771 | |
Other comprehensive loss | — | | | — | | | — | | | (1) | | | (3) | | | (4) | |
Common stock dividends declared | — | | | — | | | — | | | (175) | | | — | | | (175) | |
Balance, December 31, 2019 | 2 | | | — | | | 4,479 | | | 3,972 | | | (16) | | | 8,437 | |
Net income | — | | | — | | | — | | | 739 | | | — | | | 739 | |
Other comprehensive loss | — | | | — | | | — | | | — | | | (3) | | | (3) | |
| | | | | | | | | | | |
Balance, December 31, 2020 | 2 | | | — | | | 4,479 | | | 4,711 | | | (19) | | | 9,173 | |
Net income | — | | | — | | | — | | | 888 | | | — | | | 888 | |
Other comprehensive income | — | | | — | | | — | | | — | | | 2 | | | 2 | |
Common stock dividends declared | — | | | — | | | — | | | (150) | | | — | | | (150) | |
Balance, December 31, 2021 | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,449 | | | $ | (17) | | | $ | 9,913 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 888 | | | $ | 739 | | | $ | 771 | |
Adjustments to reconcile net income to net cash flows from operating | | | | | |
activities: | | | | | |
Depreciation and amortization | 1,088 | | | 1,209 | | | 954 | |
Allowance for equity funds | (50) | | | (98) | | | (72) | |
Changes in regulatory assets and liabilities | (189) | | | (229) | | | (55) | |
Deferred income taxes and amortization of investment tax credits | 64 | | | (124) | | | (131) | |
Other, net | (5) | | | 1 | | | 20 | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables, other receivables and other assets | 15 | | | (154) | | | 26 | |
Inventories | 8 | | | (88) | | | 23 | |
Prepaid expenses | 2 | | | (15) | | | (12) | |
Derivative collateral, net | 19 | | | 23 | | | 12 | |
Accrued property, income and other taxes, net | (37) | | | (53) | | | 22 | |
Accounts payable and other liabilities | 1 | | | 372 | | | (11) | |
Net cash flows from operating activities | 1,804 | | | 1,583 | | | 1,547 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (1,513) | | | (2,540) | | | (2,175) | |
Other, net | 12 | | | 30 | | | 11 | |
Net cash flows from investing activities | (1,501) | | | (2,510) | | | (2,164) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 984 | | | 987 | | | 989 | |
Repayments of long-term debt | (870) | | | (38) | | | (350) | |
(Repayments of) net proceeds from short-term debt | (93) | | | (37) | | | 100 | |
| | | | | |
Dividends paid | (150) | | | — | | | (175) | |
Other, net | (7) | | | (2) | | | (3) | |
Net cash flows from financing activities | (136) | | | 910 | | | 561 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 167 | | | (17) | | | (56) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 19 | | | 36 | | | 92 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 186 | | | $ | 19 | | | $ | 36 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)Organization and Operations
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2)Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") described in Note 14. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Investments
Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December 31, 2021 and 2020, PacifiCorp had 0 unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings.
Equity Method Investments
PacifiCorp utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, PacifiCorp records the investment at cost and subsequently increases or decreases the carrying value of the investment by PacifiCorp's proportionate share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. PacifiCorp records dividends or other equity distributions as reductions in the carrying value of the investment.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination, and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on PacifiCorp's assessment of the collectability of amounts owed to PacifiCorp by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 17 | | | $ | 8 | | | $ | 8 | |
Charged to operating costs and expenses, net | 13 | | | 18 | | | 13 | |
Write-offs, net | (12) | | | (9) | | | (13) | |
Ending balance | $ | 18 | | | $ | 17 | | | $ | 8 | |
Derivatives
PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or energy costs on the Consolidated Statements of Operations.
For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates are recorded as regulatory liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials, supplies and fuel stocks and are stated at the lower of average cost or net realizable value.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction ("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when PacifiCorp retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of property, plant and equipment, is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
PacifiCorp evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment supports PacifiCorp's regulated businesses the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
PacifiCorp's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Revenue Recognition
PacifiCorp uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging."
Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $264 million and $254 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Berkshire Hathaway includes PacifiCorp in its consolidated United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. PacifiCorp's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
(3)Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
Generation | 15 - 59 years | | $ | 13,679 | | | $ | 12,861 | |
Transmission | 60 - 90 years | | 7,894 | | | 7,632 | |
Distribution | 20 - 75 years | | 8,044 | | | 7,660 | |
Intangible plant(1) | 5 - 75 years | | 1,106 | | | 1,054 | |
Other | 5 - 60 years | | 1,539 | | | 1,510 | |
Utility plant in-service | | | 32,262 | | | 30,717 | |
Accumulated depreciation and amortization | | | (10,507) | | | (9,838) | |
Utility plant in-service, net | | | 21,755 | | | 20,879 | |
Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 9 | |
Plant, net | | | 21,773 | | | 20,888 | |
Construction work-in-progress | | | 1,141 | | | 1,542 | |
Property, plant and equipment, net | | | $ | 22,914 | | | $ | 22,430 | |
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
The average depreciation and amortization rate applied to depreciable property, plant and equipment was 3.5%, 4.1% and 3.3% for the years ended December 31, 2021, 2020 and 2019, respectively, including the impacts of accelerated depreciation totaling $376 million and $125 million in 2020 and 2019, respectively, for Utah's share of certain thermal plant units in 2020, including Cholla Unit No. 4 in 2020 for which operations ceased in December 2020; Oregon's and Idaho's shares of Cholla Unit No. 4 in 2020; and Oregon's share of certain retired wind equipment associated with wind repowering projects in 2020 and 2019. As discussed in Notes 6 and 9, existing regulatory liabilities primarily associated with the Utah Sustainability and Transportation Plan ("STEP") and 2017 Tax Reform benefits were utilized to accelerate depreciation of these assets.
Effective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase in depreciation expense of approximately $158 million for the year ended December 31, 2021, as compared to the year ended December 31, 2020, based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.
Unallocated Acquisition Adjustments
PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in property, plant and equipment purchased from the entity that first dedicated the assets to utility service over their net book value in those assets. These unallocated acquisition adjustments included in other property, plant and equipment had an original cost of $156 million as of December 31, 2021 and 2020, and accumulated depreciation of $143 million and $140 million as of December 31, 2021 and 2020, respectively.
(4)Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include PacifiCorp's share of the expenses of these facilities.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Facility | | Accumulated | | Construction |
| PacifiCorp | | in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Jim Bridger Nos. 1 - 4 | 67 | % | | $ | 1,523 | | | $ | 812 | | | $ | 15 | |
Hunter No. 1 | 94 | | | 489 | | | 221 | | | 8 | |
Hunter No. 2 | 60 | | | 306 | | | 138 | | | 1 | |
Wyodak | 80 | | | 477 | | | 269 | | | 8 | |
Colstrip Nos. 3 and 4 | 10 | | | 260 | | | 161 | | | 3 | |
Hermiston | 50 | | | 185 | | | 99 | | | — | |
Craig Nos. 1 and 2 | 19 | | | 369 | | | 319 | | | — | |
Hayden No. 1 | 25 | | | 77 | | | 47 | | | — | |
Hayden No. 2 | 13 | | | 44 | | | 28 | | | — | |
| | | | | | | |
Transmission and distribution facilities | Various | | 879 | | | 269 | | | 118 | |
Total | | | $ | 4,609 | | | $ | 2,363 | | | $ | 153 | |
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheets as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 11 | | | $ | 11 | |
Finance leases | 11 | | | 17 | |
Total right-of-use assets | $ | 22 | | | $ | 28 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 11 | | | $ | 11 | |
Finance leases | 12 | | | 17 | |
Total lease liabilities | $ | 23 | | | $ | 28 | |
The following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 56 | | | $ | 60 | | | $ | 77 | |
Operating | 3 | | | 3 | | | 3 | |
Finance: | | | | | |
Amortization | 5 | | | 2 | | | 1 | |
Interest | 2 | | | 2 | | | 2 | |
Short-term | 3 | | | 1 | | | 2 | |
Total lease costs | $ | 69 | | | $ | 68 | | | $ | 85 | |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 12.7 | | 13.9 | | 14.0 |
Finance leases | 10.1 | | 8.4 | | 9.1 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 3.7 | % | | 3.8 | % | | 3.7 | % |
Finance leases | 11.1 | % | | 10.5 | % | | 10.6 | % |
Cash payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2021, 2020 and 2019.
PacifiCorp has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 3 | | | $ | 3 | | | $ | 6 | |
2023 | 2 | | | 2 | | | 4 | |
2024 | 1 | | | 2 | | | 3 | |
2025 | 1 | | | 2 | | | 3 | |
2026 | 1 | | | 2 | | | 3 | |
Thereafter | 6 | | | 10 | | | 16 | |
Total undiscounted lease payments | 14 | | | 21 | | | 35 | |
Less - amounts representing interest | (3) | | | (9) | | | (12) | |
Lease liabilities | $ | 11 | | | $ | 12 | | | $ | 23 | |
(6)Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2021 | | 2020 |
| | | | | |
| | | | | |
Employee benefit plans(1) | 17 years | | $ | 286 | | | $ | 432 | |
Utah mine disposition(2) | Various | | 116 | | | 117 | |
Unamortized contract values | 2 years | | 36 | | | 42 | |
Deferred net power costs | 2 years | | 151 | | | 78 | |
Unrealized loss on derivative contracts | N/A | | — | | | 17 | |
Environmental costs | 28 years | | 108 | | | 89 | |
Asset retirement obligation | 29 years | | 241 | | | 252 | |
Demand side management (DSM)(3) | 10 years | | 211 | | | 196 | |
Other | Various | | 203 | | | 172 | |
Total regulatory assets | | | $ | 1,352 | | | $ | 1,395 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 65 | | | $ | 116 | |
Noncurrent assets | | | 1,287 | | | 1,279 | |
Total regulatory assets | | | $ | 1,352 | | | $ | 1,395 | |
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.
(2)Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the United Mine Workers of America ("UMWA") 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery.
(3)In accordance with the Utah general rate case order issued in December 2020, $185 million of amounts billed to Utah customers under the Utah STEP program were used to accelerate depreciation of certain coal-fueled generation units as discussed in Note 3.
PacifiCorp had regulatory assets not earning a return on investment of $723 million and $707 million as of December 31, 2021 and 2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining | | | | |
| Life | | 2021 | | 2020 |
| | | | | |
Cost of removal(1) | 26 years | | $ | 1,187 | | | $ | 1,125 | |
Deferred income taxes(2) | Various | | 1,307 | | | 1,463 | |
| | | | | |
Unrealized gain on regulated derivatives | 1 year | | 53 | | | — | |
Other | Various | | 221 | | | 254 | |
Total regulatory liabilities | | | $ | 2,768 | | | $ | 2,842 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 118 | | | $ | 115 | |
Noncurrent liabilities | | | 2,650 | | | 2,727 | |
Total regulatory liabilities | | | $ | 2,768 | | | $ | 2,842 | |
(1)Amounts represent estimated costs, as generally accrued through depreciation rates, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable of being passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(7)Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | |
2021: | | |
Credit facilities | | $ | 1,200 | |
Less: | | |
Short-term debt | | — | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | $ | 982 | |
| | |
2020: | | |
Credit facilities | | $ | 1,200 | |
Less: | | |
Short-term debt | | (93) | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | $ | 889 | |
As of December 31, 2021, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.
PacifiCorp has a $1.2 billion unsecured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. As of December 31, 2021, PacifiCorp did not have any commercial paper borrowings outstanding. As of December 31, 2020, PacifiCorp had $93 million of commercial paper outstanding with a weighted average interest rate of 0.16%.
The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2021 and 2020, PacifiCorp had $19 million and $11 million, respectively, of fully available letters of credit issued under committed arrangements in support of certain transactions required by third parties and generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
(8)Long-term Debt
PacifiCorp's long-term debt was as follows as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| | | | | Average | | | | Average |
| Principal | | Carrying | | Interest | | Carrying | | Interest |
| Amount | | Value | | Rate | | Value | | Rate |
| | | | | | | | | |
First mortgage bonds: | | | | | | | | | |
2.95% to 8.53%, due through 2026 | $ | 1,379 | | | $ | 1,378 | | | 4.52 | % | | $ | 2,245 | | | 4.12 | % |
2.70% to 7.70%, due 2027 to 2031 | 1,100 | | | 1,094 | | | 4.35 | | | 1,094 | | | 4.35 | |
5.25% to 6.10%, due 2032 to 2036 | 850 | | | 845 | | | 5.75 | | | 845 | | | 5.75 | |
5.75% to 6.35%, due 2037 to 2041 | 2,150 | | | 2,137 | | | 6.05 | | | 2,137 | | | 6.05 | |
4.10% due 2042 | 300 | | | 297 | | | 4.10 | | | 297 | | | 4.10 | |
2.90% to 4.15%, due 2049 to 2052 | 2,800 | | | 2,761 | | | 3.52 | | | 1,776 | | | 3.86 | |
Variable-rate series, tax-exempt bond obligations (2021-0.12% to 0.13%; 2020-0.14% to 0.16%): | | | | | | | | | |
Due 2025 | 25 | | | 25 | | | 0.12 | | | 25 | | | 0.14 | |
Due 2024 to 2025(1) | 193 | | | 193 | | | 0.13 | | | 193 | | | 0.15 | |
Total long-term debt | $ | 8,797 | | | $ | 8,730 | | | | | $ | 8,612 | | | |
| | | | | | | | | | | |
Reflected as: | | | |
| 2021 | | 2020 |
Current portion of long-term debt | $ | 155 | | | $ | 420 | |
Long-term debt | 8,575 | | | 8,192 | |
Total long-term debt | $ | 8,730 | | | $ | 8,612 | |
(1)Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the United States Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2023.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $31 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2021.
In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.
As of December 31, 2021, the annual principal maturities of long-term debt for 2022 and thereafter are as follows (in millions):
| | | | | |
| Long-term |
| Debt |
| |
2022 | $ | 155 | |
2023 | 449 | |
2024 | 591 | |
2025 | 302 | |
2026 | 100 | |
Thereafter | 7,200 | |
Total | 8,797 | |
Unamortized discount and debt issuance costs | (67) | |
| |
Total | $ | 8,730 | |
(9)Income Taxes
Income tax (benefit) expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current: | | | | | |
Federal | $ | (150) | | | $ | 19 | | | $ | 158 | |
State | 7 | | | 30 | | | 34 | |
Total | (143) | | | 49 | | | 192 | |
| | | | | |
Deferred: | | | | | |
Federal | 26 | | | (124) | | | (132) | |
State | 40 | | | 1 | | | 4 | |
Total | 66 | | | (123) | | | (128) | |
| | | | | |
Investment tax credits | (2) | | | (1) | | | (3) | |
Total income tax (benefit) expense | $ | (79) | | | $ | (75) | | | $ | 61 | |
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
State income taxes, net of federal income tax benefit | 3 | | | 3 | | | 3 | |
Effects of ratemaking | (14) | | | (22) | | | (13) | |
Federal income tax credits | (20) | | | (13) | | | (3) | |
Other | — | | | — | | | (1) | |
Effective income tax rate | (10) | % | | (11) | % | | 7 | % |
Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $112 million for 2021, including the use of $4 million to amortize certain regulatory asset balances in Wyoming and Idaho. Excess deferred income tax amortization, net of deferrals, was $132 million for 2020, including the use of $118 million to accelerate depreciation of certain retired equipment and to amortize certain regulatory balances in Idaho, Oregon and Utah. Excess deferred income taxes amortization, net of deferrals, was $93 million for 2019, including the use of $91 million to accelerate depreciation of certain retired wind equipment for Oregon.
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 682 | | | $ | 700 | |
Employee benefits | 68 | | | 93 | |
| | | |
State carryforwards | 73 | | | 73 | |
Loss contingencies | 63 | | | 63 | |
Asset retirement obligations | 73 | | | 65 | |
Other | 73 | | | 83 | |
| 1,032 | | | 1,077 | |
Deferred income tax liabilities: | | | |
Property, plant and equipment | (3,468) | | | (3,311) | |
Regulatory assets | (332) | | | (343) | |
Other | (79) | | | (50) | |
| (3,879) | | | (3,704) | |
Net deferred income tax liability | $ | (2,847) | | | $ | (2,627) | |
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2021 (in millions):
| | | | | | | | |
| | State |
| | |
Net operating loss carryforwards | | $ | 1,138 | |
Deferred income taxes on net operating loss carryforwards | | $ | 53 | |
Expiration dates | | 2023 - 2032 |
| | |
Tax credit carryforwards | | $ | 20 | |
Expiration dates | | 2022 - indefinite |
The United States Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns through December 31, 2013. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31, 2011, with the exception of Idaho, where the statute has expired through December 31, 2017, for all adjustments other than federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
(10) Employee Benefit Plans
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover certain of its employees, as well as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.
Defined Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, collectively the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Pension Settlement
Pension settlement accounting was triggered in 2021 as a result of the amount of lump sum distributions in the Retirement Plan during 2021 exceeding the service and interest cost threshold. This resulted in an interim July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the settlement accounting, PacifiCorp recognized settlement losses of $6 million, net of regulatory deferrals during the year ended December 31, 2021.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
Net periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | | $ | 2 | |
Interest cost | 29 | | | 36 | | | 44 | | | 7 | | | 9 | | | 12 | |
Expected return on plan assets | (51) | | | (56) | | | (67) | | | (9) | | | (14) | | | (21) | |
Settlement | 6 | | | — | | | — | | | — | | | — | | | — | |
Net amortization | 21 | | | 18 | | | 11 | | | 1 | | | 3 | | | — | |
Net periodic benefit cost (credit) | $ | 5 | | | $ | (2) | | | $ | (12) | | | $ | 1 | | | $ | — | | | $ | (7) | |
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 1,064 | | | $ | 1,036 | | | $ | 327 | | | $ | 334 | |
Employer contributions(1) | 5 | | | 5 | | | 1 | | | — | |
Participant contributions | — | | | — | | | 6 | | | 4 | |
Actual return on plan assets | 109 | | | 124 | | | 14 | | | 15 | |
Settlement(2) | (52) | | | — | | | — | | | — | |
Benefits paid | (68) | | | (101) | | | (24) | | | (26) | |
Plan assets at fair value, end of year | $ | 1,058 | | | $ | 1,064 | | | $ | 324 | | | $ | 327 | |
(1)Amounts represent employer contributions to the SERP.
(2)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 1,202 | | | $ | 1,167 | | | $ | 307 | | | $ | 304 | |
Service cost | — | | | — | | | 2 | | | 2 | |
Interest cost | 29 | | | 36 | | | 7 | | | 9 | |
Participant contributions | — | | | — | | | 6 | | | 4 | |
Actuarial (gain) loss | (63) | | | 100 | | | (10) | | | 14 | |
| | | | | | | |
Settlement(1) | (52) | | | — | | | — | | | — | |
| | | | | | | |
Benefits paid | (68) | | | (101) | | | (24) | | | (26) | |
Benefit obligation, end of year | $ | 1,048 | | | $ | 1,202 | | | $ | 288 | | | $ | 307 | |
Accumulated benefit obligation, end of year | $ | 1,048 | | | $ | 1,202 | | | | | |
(1)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 1,058 | | | $ | 1,064 | | | $ | 324 | | | $ | 327 | |
Less - Benefit obligation, end of year | 1,048 | | | 1,202 | | | 288 | | | 307 | |
Funded status | $ | 10 | | | $ | (138) | | | $ | 36 | | | $ | 20 | |
| | | | | | | |
Amounts recognized on the Consolidated Balance Sheets: | | | | | | | |
Other assets | $ | 63 | | | $ | 8 | | | $ | 36 | | | $ | 20 | |
Accrued employee expenses | (4) | | | (4) | | | — | | | — | |
Other long-term liabilities | (49) | | | (142) | | | — | | | — | |
Amounts recognized | $ | 10 | | | $ | (138) | | | $ | 36 | | | $ | 20 | |
The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $69 million and $61 million as of December 31, 2021 and 2020, respectively. These assets are not included in the plan assets in the above table, but are reflected in noncurrent other assets as of December 31, 2021 and 2020, respectively, on the Consolidated Balance Sheets.
As of December 31, 2021, the fair value of the plan assets for the Retirement Plan was in excess of both the projected benefit obligation and the accumulated benefit obligation.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net loss (gain) | $ | 298 | | | $ | 455 | | | $ | (28) | | | $ | (13) | |
| | | | | | | |
Regulatory deferrals(1) | 11 | | | 2 | | | 2 | | | 3 | |
Total | $ | 309 | | | $ | 457 | | | $ | (26) | | | $ | (10) | |
(1)Includes $9 million of deferrals associated with 2021 pension settlement losses.
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2021 and 2020 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | |
| | | | | Other | | |
| Regulatory | | | | Comprehensive | | |
| Asset | | | | Loss | | Total |
Pension | | | | | | | |
Balance, December 31, 2019 | $ | 422 | | | | | $ | 21 | | | $ | 443 | |
Net loss arising during the year | 27 | | | | | 5 | | | 32 | |
| | | | | | | |
Net amortization | (17) | | | | | (1) | | | (18) | |
| | | | | | | |
Total | 10 | | | | | 4 | | | 14 | |
Balance, December 31, 2020 | 432 | | | | | 25 | | | 457 | |
Net gain arising during the year | (120) | | | | | (1) | | | (121) | |
| | | | | | | |
Net amortization | (20) | | | | | (1) | | | (21) | |
Settlement | (6) | | | | | — | | | (6) | |
Total | (146) | | | | | (2) | | | (148) | |
Balance, December 31, 2021 | $ | 286 | | | | | $ | 23 | | | $ | 309 | |
| | | | | |
| Regulatory |
| Liability |
Other Postretirement | |
Balance, December 31, 2019 | $ | (20) | |
Net loss arising during the year | 13 | |
| |
Net amortization | (3) | |
Total | 10 | |
Balance, December 31, 2020 | (10) | |
Net gain arising during the year | (15) | |
| |
Net amortization | (1) | |
Total | (16) | |
Balance, December 31, 2021 | $ | (26) | |
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 2.90 | % | | 2.50 | % | | 3.25 | % | | 2.90 | % | | 2.50 | % | | 3.20 | % |
Rate of compensation increase | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan - non-union | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.40 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.27 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2021 | 0.82 | % | | 0.82 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2022 | 0.88 | % | | 0.82 | % | | 2.10 | % | | N/A | | N/A | | N/A |
2023 | 0.88 | % | | 2.00 | % | | 2.10 | % | | N/A | | N/A | | N/A |
2024 and beyond | 1.90 | % | | 2.00 | % | | 2.10 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Interest crediting rates for cash balance plan - union | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.15 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.16 | % | | 2.16 | % | | N/A | | N/A | | N/A |
2021 | 1.42 | % | | 1.42 | % | | 2.16 | % | | N/A | | N/A | | N/A |
2022 | 1.94 | % | | 1.42 | % | | 2.70 | % | | N/A | | N/A | | N/A |
2023 | 1.94 | % | | 2.40 | % | | 2.70 | % | | N/A | | N/A | | N/A |
2024 and beyond | 2.30 | % | | 2.40 | % | | 2.70 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | |
Discount rate | 2.50 | % | | 3.25 | % | | 4.25 | % | | 2.50 | % | | 3.20 | % | | 4.25 | % |
Expected return on plan assets | 6.00 | | | 6.50 | | | 7.00 | | | 2.90 | | | 4.92 | | | 6.86 | |
| | | | | | | | | | | |
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
As a result of a plan amendment effective on January 1, 2017, the benefit obligation for the Retirement Plan is no longer affected by future increases in compensation. As a result of a labor settlement reached with UMWA in December 2014, the benefit obligation for the other postretirement plan is no longer affected by healthcare cost trends.
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $— million, respectively, during 2022. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension Protection Act of 2006, as amended ("PPA of 2006"). PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the PPA of 2006. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2022 through 2026 and for the five years thereafter are summarized below (in millions):
| | | | | | | | | | | |
| Projected Benefit Payments |
| Pension | | Other Postretirement |
| | | |
2022 | $ | 96 | | | $ | 24 | |
2023 | 85 | | | 23 | |
2024 | 79 | | | 22 | |
2025 | 76 | | | 21 | |
2026 | 71 | | | 20 | |
2027-2031 | 304 | | | 87 | |
Plan Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
In 2020, the assets of the PacifiCorp Master Retirement Trust were transferred into the BHE Master Retirement Trust.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2021:
| | | | | | | | | | | |
| Pension(1) | | Other Postretirement(1) |
| % | | % |
Debt securities(2) | 55 - 85 | | 70 - 80 |
Equity securities(2) | 25- 35 | | 20 - 30 |
Other | 0 - 10 | | 0 - 1 |
| | | |
(1)The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2021: | | | | | | | | |
Cash equivalents | | $ | — | | | $ | 15 | | | $ | — | | | $ | 15 | |
Debt securities: | | | | | | | | |
United States government obligations | | 51 | | | — | | | — | | | 51 | |
| | | | | | | | |
Corporate obligations | | — | | | 299 | | | — | | | 299 | |
Municipal obligations | | — | | | 22 | | | — | | | 22 | |
Agency, asset and mortgage-backed obligations | | — | | | 38 | | | — | | | 38 | |
Equity securities: | | | | | | | | |
United States companies | | 61 | | | — | | | — | | | 61 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 112 | | | $ | 374 | | | $ | — | | | $ | 486 | |
Investment funds(2) measured at net asset value | | | | | | | | 538 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 34 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 1,058 | |
| | | | | | | | |
As of December 31, 2020: | | | | | | | | |
Cash equivalents | | $ | — | | | $ | 32 | | | $ | — | | | $ | 32 | |
Debt securities: | | | | | | | | |
United States government obligations | | 14 | | | — | | | — | | | 14 | |
International government obligations | | — | | | — | | | — | | | — | |
Corporate obligations | | — | | | 231 | | | — | | | 231 | |
Municipal obligations | | — | | | 21 | | | — | | | 21 | |
| | | | | | | | |
Equity securities: | | | | | | | | |
United States companies | | 91 | | | — | | | — | | | 91 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 105 | | | $ | 284 | | | $ | — | | | $ | 389 | |
Investment funds(2) measured at net asset value | | | | | | | | 587 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 88 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 1,064 | |
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 59% and 41%, respectively, for 2021 and 78% and 22%, respectively, for 2020, and are invested in United States and international securities of approximately 84% and 16%, respectively, for 2021 and 74% and 26%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate.
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1(1) | | Level 2(1) | | Level 3(1) | | Total |
As of December 31, 2021: | | | | | | | | |
Cash and cash equivalents | | $ | 4 | | | $ | 1 | | | $ | — | | | $ | 5 | |
Debt securities: | | | | | | | | |
United States government obligations | | 24 | | | — | | | — | | | 24 | |
| | | | | | | | |
Corporate obligations | | — | | | 79 | | | — | | | 79 | |
Municipal obligations | | — | | | 15 | | | — | | | 15 | |
Agency, asset and mortgage-backed obligations | | — | | | 35 | | | — | | | 35 | |
Equity securities: | | | | | | | | |
United States companies | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 32 | | | $ | 130 | | | $ | — | | | 162 | |
Investment funds(2) measured at net asset value | | | | | | | | 161 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 1 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 324 | |
| | | | | | | | |
As of December 31, 2020: | | | | | | | | |
Cash and cash equivalents | | $ | 8 | | | $ | 1 | | | $ | — | | | $ | 9 | |
Debt securities: | | | | | | | | |
United States government obligations | | 11 | | | — | | | — | | | 11 | |
| | | | | | | | |
Corporate obligations | | — | | | 86 | | | — | | | 86 | |
Municipal obligations | | — | | | 16 | | | — | | | 16 | |
Agency, asset and mortgage-backed obligations | | — | | | 44 | | | — | | | 44 | |
Equity securities: | | | | | | | | |
United States companies | | 4 | | | — | | | — | | | 4 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total assets in the fair value hierarchy | | $ | 23 | | | $ | 147 | | | $ | — | | | 170 | |
Investment funds(2) measured at net asset value | | | | | | | | 153 | |
Limited partnership interests(3) measured at net asset value | | | | | | | | 4 | |
| | | | | | | | |
Investments at fair value | | | | | | | | $ | 327 | |
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 39% and 61%, respectively, for 2021 and 38% and 62%, respectively, for 2020, and are invested in United States and international securities of approximately 90% and 10%, respectively, for 2021 and 93% and 7%, respectively, for 2020.
(3)Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Multiemployer and Joint Trustee Pension Plans
PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) and its subsidiary, Energy West Mining Company, previously contributed to the UMWA 1974 Pension Plan (plan number 002). Contributions to these pension plans are based on the terms of collective bargaining agreements.
As a result of the Utah Mine Disposition and UMWA labor settlement, PacifiCorp's subsidiary, Energy West Mining Company, triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp recorded its estimate of the withdrawal obligation in December 2014 when withdrawal was considered probable and deferred the portion of the obligation considered probable of recovery to a regulatory asset. PacifiCorp has subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees determined a withdrawal liability of $115 million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a variety of factors, including the results of ongoing negotiations with the plan trustees.
The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and although formed with the ability for other employers to participate in the plan, there are no other employers that participate in this plan.
The risk of participating in multiemployer pension plans generally differs from single-employer plans in that assets are pooled such that contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets cannot revert to employers. If an employer ceases participation in the plan, the employer may be obligated to pay a withdrawal liability based on the participants' unfunded, vested benefits in the plan. This occurred as a result of Energy West Mining Company's withdrawal from the UMWA 1974 Pension Plan. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers.
The following table presents PacifiCorp's participation in individually significant joint trustee and multiemployer pension plans for the years ended December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | PPA of 2006 zone status or | | | | | | | | | | | | |
| | | | plan funded status percentage for | | | | | | | | | | | | |
| | | | plan years beginning July 1, | | | | | | Contributions(1) | | |
Plan name | | Employer Identification Number | | 2021 | | 2020 | | 2019 | | Funding improvement plan | | Surcharge imposed under PPA of 2006(1) | | 2021 | | 2020 | | 2019 | | Year contributions to plan exceeded more than 5% of total contributions(2) |
Local 57 Trust Fund | | 87-0640888 | | At least 80% | | At least 80% | | At least 80% | | None | | None | | $ | 6 | | | $ | 6 | | | $ | 7 | | | 2019, 2018, 2017 |
(1) PacifiCorp's minimum contributions to the plan are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreements, subject to ERISA minimum funding requirements.
(2) For the Local 57 Trust Fund, information is for plan years beginning July 1, 2019, 2018 and 2017. Information for the plan year beginning July 1, 2020 is not yet available.
The current collective bargaining agreements governing the Local 57 Trust Fund expire in 2023.
Defined Contribution Plan
PacifiCorp's 401(k) Plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's level of contribution and, as of January 1, 2021, all participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) Plan were $40 million, $41 million and $40 million for the years ended December 31, 2021, 2020 and 2019, respectively.
(11)Asset Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $1,187 million and $1,125 million as of December 31, 2021 and 2020, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 270 | | | $ | 257 | |
Change in estimated costs | 40 | | | (11) | |
Additions | — | | | 25 | |
Retirements | (15) | | | (10) | |
Accretion | 9 | | | 9 | |
Ending balance | $ | 304 | | | $ | 270 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 5 | | | $ | 13 | |
Other long-term liabilities | 299 | | | 257 | |
| $ | 304 | | | $ | 270 | |
Certain of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.
(12)Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 81 | | | $ | 21 | | | $ | 2 | | | $ | — | | | $ | 104 | |
Commodity liabilities | (5) | | | (1) | | | (38) | | | (7) | | | (51) | |
Total | 76 | | | 20 | | | (36) | | | (7) | | | 53 | |
| | | | | | | | | |
Total derivatives | 76 | | | 20 | | | (36) | | | (7) | | | 53 | |
Cash collateral receivable | — | | | — | | | 5 | | | — | | | 5 | |
Total derivatives - net basis | $ | 76 | | | $ | 20 | | | $ | (31) | | | $ | (7) | | | $ | 58 | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 29 | | | $ | 6 | | | $ | 1 | | | $ | — | | | $ | 36 | |
Commodity liabilities | (2) | | | — | | | (23) | | | (28) | | | (53) | |
Total | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
| | | | | | | | | |
Total derivatives | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
Cash collateral receivable | — | | | — | | | 15 | | | 9 | | | 24 | |
Total derivatives - net basis | $ | 27 | | | $ | 6 | | | $ | (7) | | | $ | (19) | | | $ | 7 | |
(1)PacifiCorp's commodity derivatives are generally included in rates. As of December 31, 2021 a regulatory liability of $53 million was recorded related to the net derivative asset of $53 million. As of December 31, 2020 regulatory asset of $17 million was recorded related to the net derivative liability of $17 million.
The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Beginning balance | $ | 17 | | | $ | 62 | | | $ | 96 | |
Changes in fair value recognized in regulatory assets | (171) | | | (11) | | | (37) | |
Net (losses) gains reclassified to operating revenue | (23) | | | 3 | | | (34) | |
Net gains (losses) reclassified to energy costs | 124 | | | (37) | | | 37 | |
Ending balance | $ | (53) | | | $ | 17 | | | $ | 62 | |
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases (sales), net | Megawatt hours | | 2 | | | (1) | |
Natural gas purchases | Decatherms | | 106 | | | 100 | |
| | | | | |
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $37 million and $51 million as of December 31, 2021 and 2020, respectively, for which PacifiCorp had posted collateral of $5 million and $24 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of December 31, 2021 and 2020, PacifiCorp would have been required to post $23 million and $25 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13)Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.
The following table presents PacifiCorp's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2021: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 96 | |
Money market mutual funds | 181 | | | — | | | — | | | — | | | 181 | |
Investment funds | 27 | | | — | | | — | | | — | | | 27 | |
| $ | 208 | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 304 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — | | | $ | (51) | | | $ | — | | | $ | 13 | | | $ | (38) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — | | | $ | 36 | | | $ | — | | | $ | (3) | | | $ | 33 | |
Money market mutual funds | 6 | | | — | | | — | | | — | | | 6 | |
Investment funds | 25 | | | — | | | — | | | — | | | 25 | |
| $ | 31 | | | $ | 36 | | | $ | — | | | $ | (3) | | | $ | 64 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — | | | $ | (53) | | | $ | — | | | $ | 27 | | | $ | (26) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $5 million and $24 million as of December 31, 2021 and 2020, respectively.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 12 for further discussion regarding PacifiCorp's risk management and hedging activities.
PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 8,730 | | | $ | 10,374 | | | $ | 8,612 | | | $ | 10,995 | |
(14)Commitments and Contingencies
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. Additionally, multiple insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending.
As of December 31, 2021, PacifiCorp's assets included $14 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $193 million over the next 10 years. Included in these estimates are commitments associated with the KHSA.
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 20182021 are as follows (in millions):
| | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Thereafter | | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Thereafter | | Total |
Contract type: | | | | | | | | | | | | | | Contract type: | | | | | | | | | | | | | |
Purchased electricity contracts - | | | | | | | | | | | | | | Purchased electricity contracts - | |
commercially operable | $ | 317 |
| | $ | 194 |
| | $ | 155 |
| | $ | 152 |
| | $ | 145 |
| | $ | 1,522 |
| | $ | 2,485 |
| commercially operable | $ | 372 | | | $ | 223 | | | $ | 212 | | | $ | 194 | | | $ | 192 | | | $ | 2,190 | | | $ | 3,383 | |
Purchased electricity contracts - | | | | | | | | | | | | | | |
non-commercially operable | 13 |
| | 21 |
| | 48 |
| | 49 |
| | 49 |
| | 797 |
| | 977 |
| |
| Fuel contracts | 732 |
| | 648 |
| | 521 |
| | 326 |
| | 268 |
| | 976 |
| | 3,471 |
| Fuel contracts | 586 | | | 366 | | | 310 | | | 134 | | | 129 | | | 468 | | | 1,993 | |
Construction commitments | 888 |
| | 559 |
| | 2 |
| | — |
| | — |
| | — |
| | 1,449 |
| Construction commitments | 51 | | | 106 | | | 27 | | | — | | | — | | | — | | | 184 | |
Transmission | 108 |
| | 95 |
| | 80 |
| | 69 |
| | 63 |
| | 427 |
| | 842 |
| Transmission | 108 | | | 106 | | | 90 | | | 62 | | | 51 | | | 431 | | | 848 | |
Operating leases and easements | 7 |
| | 6 |
| | 7 |
| | 6 |
| | 5 |
| | 90 |
| | 121 |
| |
Easements | | Easements | 20 | | | 20 | | | 19 | | | 19 | | | 19 | | | 518 | | | 615 | |
Maintenance, service and | | | | | | | | | | | | | | Maintenance, service and | |
other contracts | 52 |
| | 25 |
| | 26 |
| | 16 |
| | 8 |
| | 81 |
| | 208 |
| other contracts | 113 | | | 56 | | | 53 | | | 52 | | | 51 | | | 253 | | | 578 | |
Total commitments | $ | 2,117 |
| | $ | 1,548 |
| | $ | 839 |
| | $ | 618 |
| | $ | 538 |
| | $ | 3,893 |
| | $ | 9,553 |
| Total commitments | $ | 1,250 | | | $ | 877 | | | $ | 711 | | | $ | 461 | | | $ | 442 | | | $ | 3,860 | | | $ | 7,601 | |
Purchased Electricity Contracts - Commercially Operable
As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has several power purchase agreementsPPAs with solar-powered or wind-powered generating facilities that are not included in the table above as the payments are based on the amount of energy generated and there are no minimum payments. IncludedCertain of these PPAs qualify as leases as described in the purchased electricity payments are any power purchase agreements that meet the definition of a lease. Rent expense relatedNote 2. Refer to those power purchase agreements that meet the definition of aNote 5 for variable lease totaled $26 million for 2018 and $14 million for 2017 and 2016.costs associated with these lease commitments.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are included in energy costs on the Consolidated Statements of Operations. PacifiCorp is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2018, 20172021, 2020 and 20162019 energy sources.
Purchased Electricity Contracts - Non-commercially Operable
PacifiCorp has several contracts for purchases of electricity from facilities that have not yet achieved commercial operation. To the extent any of these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant, transmission, and distribution projects.
Transmission
PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's customers.
Operating Leases and Easements
PacifiCorp has non-cancelable operating leases primarily for certain operating facilities, office space, land and equipment that expire at various dates through the year ending December 31, 2096. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp also has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located. Rent expense totaled $15 million for the years ended December 31, 2018, 2017 and 2016.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.
(14)(15)Revenue from Contracts with Customers
The following table summarizes PacifiCorp's revenueCustomer Revenue by regulated energy,line of business, with further disaggregation of regulated energyretail by customer class, for the yearyears ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Retail: | | | | | |
Residential | $ | 1,914 | | | $ | 1,910 | | | $ | 1,783 | |
Commercial | 1,559 | | | 1,578 | | | 1,522 | |
Industrial | 1,125 | | | 1,185 | | | 1,176 | |
Other retail | 249 | | | 259 | | | 230 | |
Total retail | 4,847 | | | 4,932 | | | 4,711 | |
Wholesale | 157 | | | 107 | | | 99 | |
Transmission | 143 | | | 96 | | | 98 | |
Other Customer Revenue | 108 | | | 108 | | | 78 | |
Total Customer Revenue | 5,255 | | | 5,243 | | | 4,986 | |
Other revenue | 41 | | | 98 | | | 82 | |
Total operating revenue | $ | 5,296 | | | $ | 5,341 | | | $ | 5,068 | |
|
| | | |
| 2018 |
Customer Revenue: | |
Retail: | |
Residential | $ | 1,737 |
|
Commercial | 1,513 |
|
Industrial | 1,172 |
|
Other retail | 234 |
|
Total retail | 4,656 |
|
Wholesale | 55 |
|
Transmission | 103 |
|
Other Customer Revenue | 76 |
|
Total Customer Revenue | 4,890 |
|
Other revenue | 136 |
|
Total operating revenue | $ | 5,026 |
|
Contract Assets and Liabilities
In the event one of the parties to a contract has performed before the other, PacifiCorp would recognize a contract asset or contract liability depending on the relationship between PacifiCorp's performance and the customer's payment. As of December 31, 2018 and December 31, 2017, there were no material contract assets or contract liabilities recorded on the Consolidated Balance Sheets. During the years ended December 31, 2018 and 2017, there was no material revenue recognized that was included in the contract liability balance at the beginning of the period or from performance obligations satisfied in previous periods.
(15)(16)Preferred Stock
PacifiCorp has 3,500 thousand shares of Serial Preferred Stock authorized at the stated value of $100 per share. PacifiCorp had 24 thousand shares of Serial Preferred Stock issued and outstanding as of December 31, 20182021 and 2017.2020. The outstanding preferred stock series are non-redeemable and have annual dividend rates of 6.00% and 7.00%.
In the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount equal to four4 full quarterly payments.
PacifiCorp also has 16 million shares of No Par Serial Preferred Stock and 127 thousand shares of 5% Preferred Stock authorized, but no shares were issued or outstanding as of December 31, 20182021 and 2017.2020.
(16)
(17)Common Shareholder's Equity
Through PPW Holdings, BHE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that authorized BHE's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would reduce PacifiCorp's common equity below specified percentages of defined capitalization. As of December 31, 2018,2021, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW Holdings or BHE without prior state regulatory approval to the extent that it would reduce PacifiCorp's common equity below 44% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of December 31, 2018,2021, PacifiCorp's actual common equity percentage, as calculated under this measure, was 54%, and PacifiCorp would have been permitted to dividend $2.6$3.2 billion under this commitment.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE if PacifiCorp's senior unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings, or Baa3 or lower by Moody's Investor Service, as indicated by two of the three rating services. As of December 31, 2018,2021, PacifiCorp met the minimum required senior unsecured debt ratings for making distributions.
PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 6.7.
(17)(18) Components of Accumulated Other Comprehensive Loss, Net
Accumulated other comprehensive loss, net consists of unrecognized amounts on retirement benefits, net of tax, of $13$17 million and $15$19 million as of December 31, 20182021 and 2017,2020, respectively.
(18)(19)Variable-Interest Entities
PacifiCorp holds a two-thirds66.67% interest in Bridger Coal Company ("Bridger Coal"), which supplies coal to the Jim Bridger generating facility that is owned two-thirds66.67% by PacifiCorp and one-third33.33% by PacifiCorp's joint venture partner in Bridger Coal. PacifiCorp purchases two-thirds66.67% of the coal produced by Bridger Coal, while the remaining 33.33% of the coal produced is purchased by the joint venture partner. The power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. Each joint venture partner is jointly and severally liable for the obligations of Bridger Coal. Bridger Coal's necessary working capital to carry out its mining operations is financed by contributions from PacifiCorp and its joint venture partner. PacifiCorp's equity investment in Bridger Coal was $100$45 million and $137$74 million as of December 31, 20182021 and 2017,2020, respectively. Refer to Note 1921 for information regarding related-partyrelated party transactions with Bridger Coal.
(19)Related-Party(20)Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2021 and 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 179 | | | $ | 13 | |
Restricted cash included in other current assets | 4 | | | 4 | |
Restricted cash included in other assets | 3 | | | 2 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 186 | | | $ | 19 | |
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | | |
Interest paid, net of amounts capitalized | | $ | 395 | | | $ | 348 | | | $ | 340 | |
Income taxes (received) paid, net | | $ | (120) | | | $ | 107 | | | $ | 171 | |
| | | | | | | | | | | | | | | | | | | | |
Supplemental disclosure of non-cash investing and financing activities: |
Accounts payable related to property, plant and equipment additions | | $ | 254 | | | $ | 344 | | | $ | 293 | |
| | | | | | |
(21)Related Party Transactions
PacifiCorp has an intercompany administrative services agreement and a mutual assistance agreement with BHE and its subsidiaries. Amounts charged to PacifiCorp by BHE and its subsidiaries under this agreement totaled $12$18 million, $11$10 million and $10 million during the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively. Payables associated with these administrative services were immaterial$9 million and $5 million as of December 31, 20182021 and 2017,2020, respectively. Amounts charged by PacifiCorp to BHE and its subsidiaries under this agreement as well as receivables associated with these administrative services, were immaterialtotaled $8 million, $4 million and $1 million during the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
In 2021, PacifiCorp sold wind turbines previously acquired from a third party to BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for $6 million. In 2020, PacifiCorp acquired wind turbines from BHE Wind, LLC for $147 million. The wind turbines were installed as part of newly constructed and repowered wind-powered generating facilities.
PacifiCorp also engages in various transactions with several subsidiaries of BHE in the ordinary course of business. Services provided by these subsidiaries in the ordinary course of business and charged to PacifiCorp primarily relate to wholesale electricity purchases and transmission of electricity, transportation of natural gas and employee relocation services. These expenses totaled $8$6 million, $6 million and $7 million during the years ended December 31, 2018, 20172021, 2020 and 2016, respectively. Payables associated with these services were immaterial as of December 31, 2018 and 2017, respectively. Amounts charged by PacifiCorp to subsidiaries of BHE for wholesale electricity sales in the ordinary course of business were immaterial during the years ended December 31, 2018, 2017 and 2016,2019, respectively.
PacifiCorp has long-term transportation contracts with BNSF Railway Company, ("BNSF"), an indirect wholly owned subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company. Transportation costs under these contracts were $33$19 million, $35$29 million and $37$35 million during the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively. As of December 31, 2018 and 2017, PacifiCorp had immaterial amounts of accounts payable to BNSF outstanding under these contracts, including indirect payables related to a jointly owned facility.
PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. As of December 31, 2018, federal and state income taxes payable to BHE were $10 million, and as of December 31, 2017, federalFederal and state income taxes receivable from BHE were $59$48 million and $25 million as of December 31, 2021 and 2020, respectively. For the year ended December 31, 2021, cash refunded from BHE for federal and state income taxes totaled $120 million. For the years ended December 31, 2018, 20172020 and 2016,2019, cash paid to BHE for federal and state income taxes to BHE totaled $144 million, $340$107 million and $201$171 million, respectively.
PacifiCorp transacts with its equity investees, Bridger Coal and Trapper Mining Inc. During the years ended December 31, 2018, 2017 and 2016, PacifiCorp charged Bridger Coal immaterial amounts, primarily for administrative support and management services, as well as materials, provided by PacifiCorp to Bridger Coal. Receivables for these services, as well as for certain expenses paid by PacifiCorp and reimbursed by Bridger Coal, were immaterial as of December 31, 2018 and 2017, respectively. Services provided by equity investees to PacifiCorp primarily relate to coal purchases. During the years ended December 31, 2018, 20172021, 2020 and 2016,2019, coal purchases from PacifiCorp's equity investees totaled $163$148 million, $170$145 million and $174$155 million, respectively. Payables to PacifiCorp's equity investees were $13$7 million and $18$14 million as of December 31, 20182021 and 2017,2020, respectively.
(20)Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2018 and 2017, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
Cash and cash equivalents | $ | 77 |
| | 14 |
|
Restricted cash included in other current assets | 13 |
| | 13 |
|
Restricted cash included in other assets | 2 |
| | 2 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 92 |
| | $ | 29 |
|
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
|
| | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
Interest paid, net of amounts capitalized | | $ | 347 |
| | $ | 350 |
| | $ | 350 |
|
Income taxes paid, net | | $ | 144 |
| | $ | 340 |
| | $ | 201 |
|
|
| | | | | | | | | | | | |
Supplemental disclosure of non-cash investing and financing activities: |
Accounts payable related to property, plant and equipment additions | | $ | 184 |
| | $ | 147 |
| | $ | 101 |
|
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
251
| |
Item 6. | Selected Financial Data |
Information required by
Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.7.Management's Discussion and Analysis of Financial Condition and Results of Operations
| |
Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
General
MidAmerican Funding is an Iowa limited liability company whose sole member is BHE. MidAmerican Funding owns all of the outstanding common stock of MHC, which owns all of the common stock of MidAmerican Energy, Midwest Capital and MEC Construction. MHC, MidAmerican Funding and BHE are headquartered in Des Moines, Iowa.
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy as presented in this joint filing.during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with theMidAmerican Funding's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical Financial Statements and Notes to Financial Statements each in Item 8 of this Form 10-K. MidAmerican Energy'sFunding's and MidAmerican Funding'sEnergy's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
MidAmerican Energy -
MidAmerican Energy's net income for 20182021 was $682$894 million, an increase of $77$68 million, or 13%8%, compared to 20172020 primarily due to higher electric utility margin of $122$190 million and a higherfavorable income tax benefit of $72 million, primarily due to a $21 million increase in production tax credits, a lower federal tax rate and a 2017 charge of $10 million from the Tax Cuts and Jobs Act enacted on December 22, 2017 (the "2017 Tax Reform"), and higher allowance for borrowed and equity funds of $17$105 million, partially offset by higher depreciation and amortization expense of $109$198 million, due to wind-powered generation and other plant placed in-service and increases for Iowa revenue sharing, higher operations and maintenance expense of $12$21 million and higher interest expenselower allowances for equity and borrowed funds of $13$8 million. Electric utility margin increased primarily due to a higher retail utility margin of $99 million, largely from higher volumes of 5.8% and price impacts from changes in sales mix, and higher wholesale utility margin of $93 million from higher margins per unit and higher volumes of 42.7%. Operations and maintenance expense increased primarily due to higher recoveries through bill riders of $127 million (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax benefit),costs associated with additional wind-powered generating facilities placed in-service as well as higher retail customer volumes of 5.6%, largely due to industrial growth and the favorable impact of weather and higher wholesale revenue,natural gas distribution costs, partially offset by lower average retail rates of $126 million, predominantly from the impact of a lower federal tax rate2020 costs associated with storm restoration activities. The increase in depreciation and amortization expense was primarily due to 2017 Tax Reform,higher regulatory mechanisms of $139 million and additional assets placed in-service. The favorable income tax benefit was from higher generationPTCs recognized of $64 million due to new wind-powered generating facilities placed in-service in late 2020 and purchased power costs.2021, state income tax impacts and lower pretax income.
MidAmerican Energy's net income for 20172020 was $605$826 million, an increase of $63$33 million, or 12%4%, compared to 2016, including $7 million of net expense as a result of the 2017 Tax Reform. Excluding the net effect of the 2017 Tax Reform, adjusted net income for 2017 was $612 million, an increase of $70 million, or 13%, compared to 2016. The increase was2019 primarily due to a higher income tax benefit of $199 million from additional production tax creditshigher PTCs recognized of $38$132 million, lower pretax income of $166 million and the effects of ratemaking, and lower pre-tax income,operations and higher electric utility margin of $76 million, excluding the impact of an increase in electric DSM program revenue (offset in operating expense) of $22 million,maintenance expenses, partially offset by higher maintenancedepreciation and amortization expense of $52$77 million, lower allowances for equity and borrowed funds used during construction of $45 million, higher interest expense of $23 million and lower electric and natural gas utility margins. Higher PTCs recognized were due to greater wind-powered generation driven primarily by repowering and new wind projects placed in-service in 2019. Depreciation and amortization expense increased due to additional wind-powered generating facilitiesassets placed in-service in 2019 and the timing2020, partially offset by $23 million of fossil-fueled generation maintenance, higher depreciation and amortization of $21 millionlower Iowa revenue sharing accruals. Electric utility margin decreased due to wind-powered generation and other plant placed in-service and accruals for Iowa regulatory arrangements,a lower wholesale utility margin, reflecting lower margins per unit, net of higher wholesale volumes, partially offset by a December 2016 reduction in depreciation rates, and higher property and other taxes of $7 million. Electricretail utility margin increased due tofrom higher recoveries through bill riders, highervolumes. Electric retail customer volumes higher wholesale revenue and higher transmission revenue,increased 1.2% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher coal and purchased power costs. Retailresidential customer usage. Natural gas utility margin decreased primarily due to 10.2% lower retail customer volumes increased 2.4% due to industrial growth netmainly from the unfavorable impact of lower residential and commercial volumes from milder temperatures.weather.
MidAmerican Funding -
MidAmerican Funding's net income for 20182021 was $669$883 million, an increase of $95$65 million, or 17%8%, compared to 2017. In addition to the MidAmerican Energy impacts,2020. MidAmerican Funding's net income for 2017 reflects after-tax charges of $17 million related to the tender offer of a portion of its 6.927% Senior Bonds due 2029. MidAmerican Funding's net income for 20172020 was $574$818 million, an increase of $42$37 million, or 8%5%, compared to 2016, including after-tax charges of $17 million related2019. The increases were primarily due to the tender offer and $10 million of net expense as a result of the 2017 Tax Reform. Excluding the net effect of the 2017 Tax Reform and the tender offer,changes in MidAmerican Funding's adjusted net income for 2017 was $601 million, an increase of $69 million, or 13%, compared to 2016.Energy's earnings discussed above.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.
MidAmerican Energy's cost of fuel and energy and regulated cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in MidAmerican Energy's expenses included in regulatory recovery mechanisms result in comparable changes to revenue from the related recovery mechanisms.revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explainsexplain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to runningmanaging the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin isare not a measuremeasures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
| | | | | | | | | | | | | | |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 2,529 | | | $ | 2,139 | | | $ | 390 | | 18 | % | | $ | 2,139 | | | $ | 2,237 | | | $ | (98) | | (4) | % |
Cost of fuel and energy | | 539 | | | 339 | | | 200 | | 59 | | | 339 | | | 399 | | | (60) | | (15) | |
Electric utility margin | | 1,990 | | | 1,800 | | | 190 | | 11 | % | | 1,800 | | | 1,838 | | | (38) | | (2) | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 1,003 | | | 573 | | | 430 | | 75 | % | | 573 | | | 660 | | | (87) | | (13) | % |
Natural gas purchased for resale | | 760 | | | 327 | | | 433 | | * | | 327 | | | 395 | | | (68) | | (17) | |
Natural gas utility margin | | 243 | | | 246 | | | (3) | | (1) | % | | 246 | | | 265 | | | (19) | | (7) | % |
| | | | | | | | | | | | | | |
Utility margin | | $ | 2,233 | | | $ | 2,046 | | | $ | 187 | | 9 | % | | $ | 2,046 | | | $ | 2,103 | | | $ | (57) | | (3) | % |
| | | | | | | | | | | | | | |
Other operating revenue | | 15 | | | 8 | | | 7 | | 88 | % | | 8 | | | 28 | | | (20) | | (71) | % |
Other cost of sales | | 1 | | | 1 | | | — | | — | | | 1 | | | 18 | | | (17) | | (94) | |
Operations and maintenance | | 775 | | | 754 | | | 21 | | 3 | | | 754 | | | 800 | | | (46) | | (6) | |
Depreciation and amortization | | 914 | | | 716 | | | 198 | | 28 | | | 716 | | | 639 | | | 77 | | 12 | |
Property and other taxes | | 142 | | | 135 | | | 7 | | 5 | | | 135 | | | 126 | | | 9 | | 7 | |
| | | | | | | | | | | | | | |
Operating income | | $ | 416 | | | $ | 448 | | | $ | (32) | | (7) | % | | $ | 448 | | | $ | 548 | | | $ | (100) | | (18) | % |
* Not meaningful.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
| | | | | | | | | | | | | | |
Electric utility margin: | | | | | | | | | | | | | | |
Regulated electric operating revenue | | $ | 2,283 |
| | $ | 2,108 |
| | $ | 175 |
| 8 | % | | $ | 2,108 |
| | 1,985 |
| | $ | 123 |
| 6 | % |
Cost of fuel and energy | | 487 |
| | 434 |
| | 53 |
| 12 |
| | 434 |
| | 409 |
| | 25 |
| 6 |
|
Electric utility margin | | 1,796 |
| | 1,674 |
| | 122 |
| 7 |
| | 1,674 |
| | 1,576 |
| | 98 |
| 6 |
|
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Regulated natural gas operating revenue | | 754 |
| | 719 |
| | 35 |
| 5 | % | | 719 |
| | 637 |
| | 82 |
| 13 | % |
Cost of natural gas purchased for resale | | 465 |
| | 441 |
| | 24 |
| 5 |
| | 441 |
| | 367 |
| | 74 |
| 20 |
|
Natural gas utility margin | | 289 |
| | 278 |
| | 11 |
| 4 |
| | 278 |
| | 270 |
| | 8 |
| 3 |
|
| | | | | | | | | | | | | | |
Utility margin | | 2,085 |
| | 1,952 |
| | 133 |
| 7 | % | | 1,952 |
| | 1,846 |
| | 106 |
| 6 | % |
| | | | | | | | | | | | | | |
Other operating revenue | | 12 |
| | 10 |
| | 2 |
| 20 | % | | 10 |
| | 3 |
| | 7 |
| * |
Other cost of sales | | 1 |
| | 1 |
| | — |
| — |
| | 1 |
| | — |
| | 1 |
| * |
Operations and maintenance | | 811 |
| | 799 |
| | 12 |
| 2 |
| | 799 |
| | 708 |
| | 91 |
| 13 |
|
Depreciation and amortization | | 609 |
| | 500 |
| | 109 |
| 22 |
| | 500 |
| | 479 |
| | 21 |
| 4 |
|
Property and other taxes | | 125 |
| | 119 |
| | 6 |
| 5 |
| | 119 |
| | 112 |
| | 7 |
| 6 |
|
Operating income | | $ | 551 |
| | $ | 543 |
| | $ | 8 |
| 1 | % | | $ | 543 |
| | $ | 550 |
| | $ | (7 | ) | (1 | )% |
Regulated Electric Utility Margin
A comparison of key operating results related to regulated electric utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 2,529 | | | $ | 2,139 | | | $ | 390 | | | 18 | % | | $ | 2,139 | | | $ | 2,237 | | | $ | (98) | | | (4) | % |
Cost of fuel and energy | 539 | | | 339 | | | 200 | | | 59 | | | 339 | | | 399 | | | (60) | | | (15) | |
Utility margin | $ | 1,990 | | | $ | 1,800 | | | $ | 190 | | | 11 | % | | $ | 1,800 | | | $ | 1,838 | | | $ | (38) | | | (2) | % |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 6,718 | | | 6,687 | | | 31 | | | — | % | | 6,687 | | | 6,575 | | | 112 | | | 2 | % |
Commercial | 3,841 | | | 3,707 | | | 134 | | | 4 | | | 3,707 | | | 3,921 | | | (214) | | | (5) | |
Industrial | 15,944 | | | 14,645 | | | 1,299 | | | 9 | | | 14,645 | | | 14,127 | | | 518 | | | 4 | |
Other | 1,571 | | | 1,484 | | | 87 | | | 6 | | | 1,484 | | | 1,578 | | | (94) | | | (6) | |
Total retail | 28,074 | | | 26,523 | | | 1,551 | | | 6 | | | 26,523 | | | 26,201 | | | 322 | | | 1 | |
Wholesale | 16,011 | | | 11,219 | | | 4,792 | | | 43 | | | 11,219 | | | 10,000 | | | 1,219 | | | 12 | |
Total sales | 44,085 | | | 37,742 | | | 6,343 | | | 17 | % | | 37,742 | | | 36,201 | | | 1,541 | | | 4 | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 804 | | 795 | | 9 | | 1 | % | | 795 | | 786 | | 9 | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 75.84 | | | $ | 72.57 | | | $ | 3.27 | | | 5 | % | | $ | 72.57 | | | $ | 74.01 | | | $ | (1.44) | | | (2) | % |
Wholesale | $ | 18.92 | | | $ | 11.08 | | | $ | 7.84 | | | 71 | % | | $ | 11.08 | | | $ | 21.84 | | | $ | (10.76) | | | (49) | % |
| | | | | | | | | | | | | | | |
Heating degree days | 5,704 | | | 5,932 | | | (228) | | | (4) | % | | 5,932 | | | 6,661 | | | (729) | | | (11) | % |
Cooling degree days | 1,331 | | | 1,172 | | | 159 | | | 14 | % | | 1,172 | | | 1,152 | | | 20 | | | 2 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Wind and other(2) | 23,374 | | | 20,668 | | | 2,706 | | | 13 | % | | 20,668 | | | 16,136 | | | 4,532 | | | 28 | % |
Coal | 12,313 | | | 7,217 | | | 5,096 | | | 71 | | | 7,217 | | | 12,182 | | | (4,965) | | | (41) | |
Nuclear | 3,934 | | | 3,927 | | | 7 | | | — | | | 3,927 | | | 3,849 | | | 78 | | | 2 | |
Natural gas | 1,398 | | | 675 | | | 723 | | | * | | 675 | | | 441 | | | 234 | | | 53 | |
Total energy generated | 41,019 | | | 32,487 | | | 8,532 | | | 26 | | | 32,487 | | | 32,608 | | | (121) | | | — | |
Energy purchased | 3,865 | | | 5,979 | | | (2,114) | | | (35) | | | 5,979 | | | 4,292 | | | 1,687 | | | 39 | |
Total | 44,884 | | | 38,466 | | | 6,418 | | | 17 | % | | 38,466 | | | 36,900 | | | 1,566 | | | 4 | % |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 7.12 | | | $ | 4.74 | | | $ | 2.38 | | | 50 | % | | $ | 4.74 | | | $ | 7.53 | | | $ | (2.79) | | | (37) | % |
Energy purchased | $ | 64.04 | | | $ | 30.94 | | | $ | 33.10 | | | * | | $ | 30.94 | | | $ | 35.82 | | | $ | (4.88) | | | (14) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Electric utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 2,283 |
| | $ | 2,108 |
| | $ | 175 |
| | 8 | % | | $ | 2,108 |
| | $ | 1,985 |
| | $ | 123 |
| | 6 | % |
Cost of fuel and energy(1) | 487 |
| | 434 |
| | 53 |
| | 12 |
| | 434 |
| | 409 |
| | 25 |
| | 6 |
|
Electric utility margin | $ | 1,796 |
| | $ | 1,674 |
| | $ | 122 |
| | 7 |
| | $ | 1,674 |
| | $ | 1,576 |
| | $ | 98 |
| | 6 |
|
| | | | | | | | | | | | | | | |
Electricity Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 6,763 |
| | 6,207 |
| | 556 |
| | 9 | % | | 6,207 |
| | 6,408 |
| | (201 | ) | | (3 | )% |
Commercial | 3,897 |
| | 3,761 |
| | 136 |
| | 4 |
| | 3,761 |
| | 3,812 |
| | (51 | ) | | (1 | ) |
Industrial | 13,587 |
| | 12,957 |
| | 630 |
| | 5 |
| | 12,957 |
| | 12,115 |
| | 842 |
| | 7 |
|
Other | 1,604 |
| | 1,567 |
| | 37 |
| | 2 |
| | 1,567 |
| | 1,589 |
| | (22 | ) | | (1 | ) |
Total retail | 25,851 |
| | 24,492 |
| | 1,359 |
| | 6 |
| | 24,492 |
| | 23,924 |
| | 568 |
| | 2 |
|
Wholesale | 11,181 |
| | 9,165 |
| | 2,016 |
| | 22 |
| | 9,165 |
| | 8,489 |
| | 676 |
| | 8 |
|
Total sales | 37,032 |
| | 33,657 |
| | 3,375 |
| | 10 |
| | 33,657 |
| | 32,413 |
| | 1,244 |
| | 4 |
|
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 780 |
| | 770 |
| | 10 |
| | 1 | % | | 770 |
| | 760 |
| | 10 |
| | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 74.12 |
| | $ | 73.88 |
| | $ | 0.24 |
| | — | % | | $ | 73.88 |
| | $ | 71.86 |
| | $ | 2.02 |
| | 3 | % |
Wholesale | $ | 25.63 |
| | $ | 23.42 |
| | $ | 2.21 |
| | 9 | % | | $ | 23.42 |
| | $ | 22.95 |
| | $ | 0.47 |
| | 2 | % |
| | | | | | | | | | | | | | | |
Heating degree days | 6,627 |
| | 5,492 |
| | 1,135 |
| | 21 | % | | 5,492 |
| | 5,321 |
| | 171 |
| | 3 | % |
Cooling degree days | 1,307 |
| | 1,117 |
| | 190 |
| | 17 | % | | 1,117 |
| | 1,314 |
| | (197 | ) | | (15 | )% |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Coal | 15,811 |
| | 13,598 |
| | 2,213 |
| | 16 | % | | 13,598 |
| | 13,179 |
| | 419 |
| | 3 | % |
Wind and other(2) | 13,627 |
| | 12,932 |
| | 695 |
| | 5 |
| | 12,932 |
| | 11,684 |
| | 1,248 |
| | 11 |
|
Nuclear | 3,869 |
| | 3,850 |
| | 19 |
| | — |
| | 3,850 |
| | 3,912 |
| | (62 | ) | | (2 | ) |
Natural gas | 661 |
| | 360 |
| | 301 |
| | 84 |
| | 360 |
| | 556 |
| | (196 | ) | | (35 | ) |
Total energy generated | 33,968 |
| | 30,740 |
| | 3,228 |
| | 11 |
| | 30,740 |
| | 29,331 |
| | 1,409 |
| | 5 |
|
Energy purchased | 3,837 |
| | 3,603 |
| | 234 |
| | 6 |
| | 3,603 |
| | 3,882 |
| | (279 | ) | | (7 | ) |
Total | 37,805 |
| | 34,343 |
| | 3,462 |
| | 10 |
| | 34,343 |
| | 33,213 |
| | 1,130 |
| | 3 |
|
* Not meaningful.
(1) GWh amounts are net of energy used by the related generating facilities.
| |
(1) | GWh amounts are net of energy used by the related generating facilities. |
| |
(2) | All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits(2) All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities. |
For 2018 compared to 2017, regulated electric utility margin increased $122 million primarily due to:
| |
(1) | Higher retail utility margin of $73 million due to - |
an increase(3) The average cost per MWh of $127 million from higher recoveries through bill riders, (substantially offset inenergy generated includes only the cost of fuel and energy, operations and maintenance expense and income tax benefit);associated with the generating facilities.
an increase of $58 million from non-weather-related usage factors, including higher industrial sales volumes;
an increase of $33 million from the impact of weather;
an increase of $4 million from various other revenue; partially offset by
a decrease of $126 million in averages rates, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform; and
a decrease of $23 million from higher retail energy costs due to higher generation and purchased power costs;
| |
(2) | Higher wholesale utility margin of $52 million due to higher margins per unit from higher market prices and lower fuel costs on higher sales volumes; partially offset by |
| |
(3) | Lower Multi-Value Projects ("MVP") transmission revenue of $3 million due to refund accruals. |
For 2017 compared to 2016, regulated electric utility margin increased $98 million primarily due to:
| |
(1) | Higher retail utility margin of $51 million due to - |
an increase of $73 million from higher recoveries through bill riders, including $22 million of electric DSM program revenue (offset in operating expense);
an increase of $32 million from non-weather-related usage factors, including higher industrial sales volumes; partially offset by
a decrease of $33 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs; and
a decrease of $21 million from the impact of milder temperatures;
| |
(2) | Higher wholesale utility margin of $32 million due to higher margins per unit from higher market prices, greater availability of lower cost generation for wholesale purposes and higher sales volumes; and |
| |
(3) | Higher MVP transmission revenue of $13 million due to continued capital additions. |
Regulated Natural Gas Utility Margin
A comparison of key operating results related to regulated natural gas utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,003 | | | $ | 573 | | | $ | 430 | | | 75 | % | | $ | 573 | | | $ | 660 | | | $ | (87) | | | (13) | % |
Natural gas purchased for resale | 760 | | | 327 | | | 433 | | | * | | 327 | | | 395 | | | (68) | | | (17) | |
Utility margin | $ | 243 | | | $ | 246 | | | $ | (3) | | | (1) | % | | $ | 246 | | | $ | 265 | | | $ | (19) | | | (7) | % |
| | | | | | | | | | | | | | | |
Throughput (000's Dths): | | | | | | | | | | | | | | | |
Residential | 48,984 | | | 51,023 | | | (2,039) | | | (4) | % | | 51,023 | | | 56,101 | | | (5,078) | | | (9) | % |
Commercial | 23,240 | | | 23,336 | | | (96) | | | — | | | 23,336 | | | 27,333 | | | (3,997) | | | (15) | |
Industrial | 5,287 | | | 5,275 | | | 12 | | | — | | | 5,275 | | | 5,258 | | | 17 | | | — | |
Other | 68 | | | 74 | | | (6) | | | (8) | | | 74 | | | 77 | | | (3) | | | (4) | |
Total retail sales | 77,579 | | | 79,708 | | | (2,129) | | | (3) | | | 79,708 | | | 88,769 | | | (9,061) | | | (10) | |
Wholesale sales | 34,337 | | | 34,691 | | | (354) | | | (1) | | | 34,691 | | | 36,886 | | | (2,195) | | | (6) | |
Total sales | 111,916 | | | 114,399 | | | (2,483) | | | (2) | | | 114,399 | | | 125,655 | | | (11,256) | | | (9) | |
Natural gas transportation service | 112,631 | | | 110,263 | | | 2,368 | | | 2 | | | 110,263 | | | 112,143 | | | (1,880) | | | (2) | |
Total throughput | 224,547 | | | 224,662 | | | (115) | | | — | % | | 224,662 | | | 237,798 | | | (13,136) | | | (6) | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 781 | | | 774 | | | 7 | | | 1 | % | | 774 | | | 766 | | | 8 | | | 1 | % |
Average revenue per retail Dth sold | $ | 10.59 | | | $ | 5.91 | | | $ | 4.68 | | | 79 | % | | $ | 5.91 | | | $ | 6.03 | | | $ | (0.12) | | | (2) | % |
| | | | | | | | | | | | | | | |
Heating degree days | 6,000 | | | 6,253 | | | (253) | | | (4) | % | | 6,253 | | | 6,980 | | | (727) | | | (10) | % |
| | | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | $ | 7.95 | | | $ | 3.29 | | | $ | 4.66 | | | * | | $ | 3.29 | | | $ | 3.47 | | | $ | (0.18) | | | (5) | % |
| | | | | | | | | | | | | | | |
Combined retail and wholesale average cost of natural gas per Dth sold | $ | 6.79 | | | $ | 2.86 | | | $ | 3.93 | | | * | | $ | 2.86 | | | $ | 3.14 | | | $ | (0.28) | | | (9) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Natural gas utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 754 |
| | $ | 719 |
| | $ | 35 |
| | 5 | % | | $ | 719 |
| | $ | 637 |
| | $ | 82 |
| | 13 | % |
Cost of natural gas purchased for resale | 465 |
| | 441 |
| | 24 |
| | 5 |
| | 441 |
| | 367 |
| | 74 |
| | 20 |
|
Natural gas utility margin | $ | 289 |
| | $ | 278 |
| | $ | 11 |
| | 4 |
| | $ | 278 |
| | $ | 270 |
| | $ | 8 |
| | 3 |
|
| | | | | | | | | | | | | | | |
Natural gas throughput (000's Dths): | | | | | | | | | | | | | | | |
Residential | 54,798 |
| | 46,366 |
| | 8,432 |
| | 18 | % | | 46,366 |
| | 46,020 |
| | 346 |
| | 1 | % |
Commercial | 26,382 |
| | 23,434 |
| | 2,948 |
| | 13 |
| | 23,434 |
| | 23,345 |
| | 89 |
| | — |
|
Industrial | 5,777 |
| | 4,725 |
| | 1,052 |
| | 22 |
| | 4,725 |
| | 5,079 |
| | (354 | ) | | (7 | ) |
Other | 48 |
| | 38 |
| | 10 |
| | 26 |
| | 38 |
| | 37 |
| | 1 |
| | 3 |
|
Total retail sales | 87,005 |
| | 74,563 |
| | 12,442 |
| | 17 |
| | 74,563 |
| | 74,481 |
| | 82 |
| | — |
|
Wholesale sales | 39,267 |
| | 39,735 |
| | (468 | ) | | (1 | ) | | 39,735 |
| | 38,813 |
| | 922 |
| | 2 |
|
Total sales | 126,272 |
| | 114,298 |
| | 11,974 |
| | 10 |
| | 114,298 |
| | 113,294 |
| | 1,004 |
| | 1 |
|
Gas transportation service | 102,198 |
| | 92,136 |
| | 10,062 |
| | 11 |
| | 92,136 |
| | 83,610 |
| | 8,526 |
| | 10 |
|
Total natural gas throughput | 228,470 |
| | 206,434 |
| | 22,036 |
| | 11 |
| | 206,434 |
| | 196,904 |
| | 9,530 |
| | 5 |
|
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 759 |
| | 751 |
| | 8 |
| | 1 | % | | 751 |
| | 742 |
| | 9 |
| | 1 | % |
Average revenue per retail Dth sold | $ | 6.89 |
| | $ | 7.64 |
| | $ | (0.75 | ) | | (10 | )% | | $ | 7.64 |
| | $ | 6.85 |
| | $ | 0.79 |
| | 12 | % |
Average cost of natural gas per retail Dth sold | $ | 4.02 |
| | $ | 4.41 |
| | $ | (0.39 | ) | | (9 | )% | | $ | 4.41 |
| | $ | 3.70 |
| | $ | 0.71 |
| | 19 | % |
| | | | | | | | | | | | | | | |
Combined retail and wholesale average cost of natural gas per Dth sold | $ | 3.69 |
| | $ | 3.86 |
| | $ | (0.17 | ) | | (4 | )% | | $ | 3.86 |
| | $ | 3.24 |
| | $ | 0.62 |
| | 19 | % |
| | | | | | | | | | | | | | | |
Heating degree days | 6,843 |
| | 5,788 |
| | 1,055 |
| | 18 | % | | 5,788 |
| | 5,616 |
| | 172 |
| | 3 | % |
* Not meaningful.
For 2018 compared
Year Ended December 31, 2021 Compared to 2017, regulated natural gas utility margin increased $11 million primarily due to:
| |
(1) | An increase of $16 million from higher retail sales volumes due primarily to the impact of colder winter temperatures; |
| |
(2) | An increase of $2 million from higher natural gas transportation services; partially offset by |
| |
(3) | A decrease of $9 million from rate and non-weather-related usage factors, including the impact of a lower federal tax rate due to 2017 Tax Reform. |
Year Ended December 31, 2020
For 2017 compared to 2016, regulated natural gas utility margin increased $8 million due to:
| |
(1) | higher DSM program revenue (offset in operations and maintenance expense) of $3 million; |
| |
(2) | higher retail sales volumes of $2 million from colder winter temperatures; |
| |
(3) | higher gas transportation throughput of $2 million and |
| |
(4) | higher average per-unit margin of $2 million. |
Operating Expenses
MidAmerican Energy -
Operations and maintenance Electric utility marginincreased $12$190 million, or 11%, for 20182021 compared to 20172020 primarily due to:
•a $99 million increase in retail utility margin primarily due to $50 million from higher usage for certain industrial customers; $13 million from the favorable impact of weather; $19 million due to price impacts from changes in sales mix; $10 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit) and $6 million from liquidated damages related to a wind-powered generation project. Retail customer volumes increased 5.8%; and
•a $93 million increase in wholesale utility margin due to higher margins per unit of $52 million, reflecting higher market prices, net of higher energy costs, and higher volumes of 42.7%; partially offset by
•a $2 million decrease in Multi-Value Projects ("MVP") transmission revenue.
Natural gas utility margin decreased $3 million, or 1%, for 2021 compared to 2020 primarily due to:
•a $6 million decrease from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit);
•a $3 million decrease due to the unfavorable impact of weather, partially offset by price impacts from changes in sales mix; partially offset by
•a $4 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•a $2 million increase in natural gas transportation margin, reflecting higher volumes.
Operations and maintenance increased $21 million, or 3%, for 2021 compared to 2020 primarily due higher other generation operations and maintenance expenses of $23$7 million fromdue to additional wind turbines and easements, higher DSMenergy efficiency program expense of $7 million (offset in operating revenue), higher natural gas distribution costs of $6 million and higher transmission operations costs from MISO of $4$3 million, both of which are recoverable in bill riders and offset in operating revenue, partially offset by lower electric distribution and transmission maintenancecosts of $13 million primarily from tree-trimming and emergency outage work and lower fossil-fueled and nuclear generation maintenance expense of $8 million.
Operations and maintenance increased $91 million for 2017 compared to 2016 due to higher DSM program expense of $25 million and higher transmission operations costs from MISO of $6 million, both of which are recoverable in bill riders and offset in operating revenue, higher coal-fueled and nuclear generation maintenance of $22 million substantially due to the timing of coal-fueled generation outages, higher wind-powered generation maintenance of $18 million from additional wind turbines and higher electric distribution and transmission maintenance of $12$11 million due to tree trimming costs.storm restoration costs in 2020.
Depreciation and amortization increased $109$198 million, or 28%, for 20182021 compared to 20172020 primarily due to $114 million from higher accruals for Iowa revenue sharing accruals, $25 million from a regulatory mechanism that provides customers the retail energy benefits of $44 millioncertain wind-powered generation projects and $67$59 million related to new and repowered wind-powered generating facilities and other plant placed in-service.
Depreciation and amortization increased $21 million for 2017 compared to 2016 due to utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016 and accruals for Iowa regulatory arrangements of $15 million, partially offset by $31 million from lower depreciation rates implemented in December 2016.
Property and other taxes increased $6$7 million, or 5%, for 20182021 compared to 20172020 primarily due to higher wind turbine property taxes and other real estate taxes.
Property and other taxes increased $7Interest expense decreased $2 million, or 1%, for 20172021 compared to 2016 due to higher Iowa replacement taxes from higher sales volumes and higher wind turbine property taxes.
Other Income and (Expense)
MidAmerican Energy -
Interest expense increased $13 million for 2018 compared to 20172020 primarily due to highera decrease in a regulatory carrying charge and lower variable interest expense from the issuance of $700 million of first mortgage bonds in February 2018 and $150 million of variable rate, tax-exempt bonds in December 2017,rates, partially offset by the redemption of $350 million of senior notes in March 2018.a higher average long-term debt balance.
Interest expense increased $18 million for 2017 compared to 2016 due to higher interest expense from the issuance of $850 million of first mortgage bonds in February 2017 and $30 million of variable rate tax-exempt bonds in December 2016, partially offset by the redemption of $250 million of 5.95% Senior Notes in February 2017. Refer to Note 8 of Notes to Financial Statements in Item 8 of this Form 10-K for further discussion of first mortgage bonds.
Allowance for borrowed and equity funds increased $17 decreased $8 million, or 13%, for 20182021 compared to 20172020 primarily due to higherlower construction work-in-progress balances related to the construction of wind-powered generating facilities and wind turbine repoweringgeneration projects.
AllowanceOther, net increased $1 million, or 2%, for borrowed and equity funds increased $29 million for 20172021 compared to 20162020 primarily due to higher construction work-in-progress balances related to the constructioncash surrender values of wind-powered generating facilities and the wind turbine repowering project.
Other, net decreased $7 million for 2018 compared to 2017 primarily due to lower returns on corporate-owned life insurance policies.
Other, net increased $8 million for 2017 compared to 2016 due to higher returns from corporate-owned life insurance policies and higher interest income from favorable cash positions,lower non-service costs of postretirement employee benefit plans, partially offset by a gain of $5 million in 2016 on the redemption of MidAmerican Energy's investments in auction rate securities.
MidAmerican Funding -
In addition to the fluctuations discussed above for MidAmerican Energy, MidAmerican Funding's other, net for 2017 reflects a pre-tax charge of $29 million from the early redemptioncontribution of land to a portion of MidAmerican Funding's 6.927% Senior Bonds due 2029 and for 2016 reflects income of $2 million from a partnership's sale of a real estate investment.joint venture in 2020.
Income Tax Benefit
MidAmerican Energy -
MidAmerican Energy's income tax benefit increased $72$105 million, or 18%, for 20182021 compared to 2017,2020, and the effective tax rate was (60)(308)% for 20182021 and (43)(223)% for 2017. The change in the effective tax rate was substantially due to the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, an increase of $21 million in production tax credits and the effects of ratemaking.
MidAmerican Energy's income tax benefit increased $51 million for 2017 compared to 2016, and the effective tax rate was (43)% for 2017 and (32)% for 2016.2020. The change in the effective tax rate was substantially due to an increase of $38$64 million in productionPTCs, state income tax creditsimpacts and the effects of ratemaking, partially offset by the impact of the 2017 Tax Reform and higher pre-tax income.lower pretax income in 2021.
Federal renewable electricity production tax creditsPTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a prescribed per-kilowatt rate pursuant to the applicable federal income tax law andlaw. Qualifying generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in service.in-service. Beginning in late 2014, some of MidAmerican Energy's wind-powered generating facilities surpassed the 10-year eligibility period and are no longerfor earning the credits. AMost of those facilities have since been repowered, and under IRS rules, qualifying repowered facilities are eligible for the available credits, for 10 years from the date they are returned to service. Refer to "Capital Expenditures" in Liquidity and Capital Resources for additional information about repowering and new wind-powered generation placed in-service. The full credit per kilowatt hour of $0.024was $0.025 for 2018 and 2017 and $0.023 for 20162019 through 2021. The full credit, or a portion thereof, was applied to the annual production of eligible facilities, which resulted in $308$574 million, $287$510 million and $249$378 million respectively,of PTCs in production tax credits.2021, 2020 and 2019, respectively.
MidAmerican Funding -
MidAmerican Funding's incomeIncome tax benefit for MidAmerican Funding increased $60$106 million, or 18%, for 20182021 compared to 2017,2020, and the effective tax rate was (64)(335)% for 20182021 and (54)(235)% for 2017. MidAmerican Funding's income tax benefit increased $63 million for 2017 compared to 2016, and the effective tax rate was (54)% for 2017 and (35)% for 2016.2020. The change in effective tax rates was due principally to the factors discussed for MidAmerican Energy. Additionally,
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
MidAmerican Energy -
Electric utility margin decreased $38 million, or 2%, for 2020 compared to 2019 primarily due to:
•a $60 million decrease in wholesale utility margin due to lower margins per unit of $78 million, reflecting lower market prices, partially offset by lower energy costs and higher volumes of 12.2%; partially offset by
•an $18 million increase in retail utility margin primarily due to an increase of $23 million from non-weather-related factors, net of price impacts from sales mix, including increased usage for certain industrial customers and the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage; an increase of $1 million, net of energy costs, from higher recoveries through bill riders, primarily related to lower refunds related to the ratemaking treatment of 2017 reflects anTax Reform (offset in income tax benefit) and higher transmission cost recoveries (offset in operations and maintenance expense), substantially offset by a decrease of $28 million in electric energy efficiency program revenue (offset in operations and maintenance expense) and the PTC component of the EAC (offset in income tax benefit); partially offset by a decrease of $3 million from the impact of weather. Retail customer volumes increased 1.2%; and
•a $4 million increase in MVP transmission revenue.
Natural gas utility margin decreased $19 million, or 7%, for 2020 compared to 2019 primarily due to:
•a decrease of $10 million in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•a decrease of $9 million from the unfavorable impact of weather in the first quarter.
Operations and maintenance decreased $46 million, or 6%, for 2020 compared to 2019 primarily due to lower energy efficiency program expense of $38 million (offset in operating revenue), lower fossil-fueled generation maintenance of $14 million, lower natural gas distribution expenses of $10 million, lower electric distribution operations expenses of $7 million, a nuclear property insurance premium refund of $5 million and decreases in benefit plan service costs and healthcare and other administrative costs, partially offset by higher wind-powered generation expenses of $21 million due to new and repowered wind-powered generating facilities placed in-service in 2019 and easements, higher electric distribution maintenance expenses of $13 million largely driven by storm restoration related to a significant wind storm in August 2020 and higher transmission operations costs from MISO of $5 million (offset in operating revenue).
Depreciation and amortization increased $77 million, or 12%, for 2020 compared to 2019 primarily due to $95 million related to new and repowered wind-powered generating facilities and other plant placed in-service, partially offset by lower Iowa revenue sharing accruals of $23 million.
Property and other taxes increased $9 million, or 7%, for 2020 compared to 2019 due to higher wind turbine property taxes and other real estate taxes.
Interest expense increased $23 million, or 8%, for 2020 compared to 2019 primarily due to higher average long-term debt balances.
Allowance for borrowed and equity funds decreased $45 million, or 43%, for 2020 compared to 2019 primarily due to lower construction work-in-progress balances related to new and repowered wind-powered generation projects.
Other, net increased $2 million, or 4%, for 2020 compared to 2019 primarily due to lower non-service costs of postretirement employee benefit plans and a chargegain from the contribution of $29land to a joint venture in 2020, partially offset by lower interest income due to an unfavorable cash position and lower cash surrender values of corporate-owned life insurance policies.
Income tax benefit increased $199 million, or 54%, for 2020 compared to 2019, and the early redemptioneffective tax rate was (223)% for 2020 and (88)% for 2019. The change in the effective tax rate was substantially due to an increase of a portion$132 million in PTCs, state income tax impacts, the effects of ratemaking and lower pretax income in 2020.
MidAmerican Funding's 6.927% Senior BondsFunding -
Income tax benefit for MidAmerican Funding increased $197 million, or 52%, for 2020 compared to 2019, and the effective tax rate was (235)% for 2020 and (93)% for 2019. The change in effective tax rates was due 2029.principally to the factors discussed for MidAmerican Energy.
Liquidity and Capital Resources
As of December 31, 2018,2021, MidAmerican Energy's and MidAmerican Funding's total net liquidity were as follows (in millions):
|
| | | | |
MidAmerican Energy: | | |
Cash and cash equivalents | | $ | — |
|
| | |
Credit facilities, maturing 2019 and 2021(1) | | 1,305 |
|
Less: | | |
Short-term debt | | (240 | ) |
Tax-exempt bond support | | (370 | ) |
Net credit facilities | | 695 |
|
MidAmerican Energy total net liquidity | | $ | 695 |
|
| | |
MidAmerican Funding: | | |
MidAmerican Energy total net liquidity | | $ | 695 |
|
Cash and cash equivalents | | 1 |
|
MHC, Inc. credit facility, maturing 2019 | | 4 |
|
MidAmerican Funding total net liquidity | | $ | 700 |
|
| | | | | | | | |
(1)MidAmerican Energy: | As of December 31, 2018, | |
Cash and cash equivalents | | $ | 232 | |
| | |
Credit facilities, maturing 2022 and 2024 | | 1,505 | |
Less: | | |
| | |
Tax-exempt bond support | | (370) | |
Net credit facilities | | 1,135 | |
MidAmerican Energy had a $400 million unsecuredtotal net liquidity | | $ | 1,367 | |
| | |
MidAmerican Funding: | | |
MidAmerican Energy total net liquidity | | $ | 1,367 | |
Cash and cash equivalents | | 1 | |
MHC, Inc. credit facility, expiring November 2019, which it terminated in January 2019.maturing 2022 | | 4 | |
MidAmerican Funding total net liquidity | | $ | 1,372 | |
Operating Activities
MidAmerican Energy's net cash flows from operating activities were $1,508$1,617 million, $1,396$1,543 million and $1,403$1,490 million for 2018, 20172021, 2020 and 2016,2019, respectively. MidAmerican Funding's net cash flows from operating activities were $1,516$1,605 million, $1,380$1,536 million and $1,393$1,475 million for 2018, 20172021, 2020 and 2016,2019, respectively. Cash flows from operating activities increased for 20182021 compared to 20172020 primarily due to higher cashincome tax receipts, lower payments for the settlement of AROs and lower interest payments. Cash flows from operating activities increased for 2020 compared to 2019 primarily due to higher income tax receipts and lower payments to vendors, partially offset by higher payments for the settlement of AROs, lower utility margins for MidAmerican Energy's regulated electric and natural gas businesses higher income tax receipts and higher DSM cost recovery cash inflows. Cash flows from operating activities decreased for 2017 compared to 2016 primarily due to lower income tax receipts and higher interest payments partially offset by higher cash margins for MidAmerican Energy's regulated electric business, including a reductiondue to long-term debt issued in fuel inventories.October 2019.
The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the year ended December 31, 2021.
Investing Activities
MidAmerican Energy's net cash flows from investing activities were $(2,310)$(1,911) million, $(1,776)$(1,826) million and $(1,605)$(2,801) million for 2018, 20172021, 2020 and 2016,2019, respectively. MidAmerican Funding's net cash flows from investing activities were $(2,310)$(1,912) million, $(1,779)$(1,825) million and $(1,604)$(2,801) million for 2018, 20172021, 2020 and 2016,2019, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust, and in 2016, proceeds from the redemption of MidAmerican Energy's investments in auction rate securities. In 2018, proceeds from sales of other investments includes $15 million for the transfer of corporate aircraft to BHE, and other investment proceeds relates primarily to company-owned life insurance policies.
Financing Activities
MidAmerican Energy's net cash flows from financing activities were $576$488 million, $636$(2) million and $123$1,585 million for 2018, 20172021, 2020 and 2016,2019, respectively. MidAmerican Funding's net cash flows from financing activities were $569$501 million, $654$4 million and $133$1,600 million for 2018, 20172021, 2020 and 2016,2019, respectively. In February 2018,July 2021, MidAmerican Energy issued $700$500 million of its 3.65% First Mortgage Bonds due 2048. In March 2018, MidAmerican Energy repaid $350 million of its 5.30% Senior Notes due March 2018. In December 2017, the Iowa Finance Authority issued $150 million of its variable-rate, tax-exempt Solid Waste Facilities Revenue Bonds due December 2047, the restricted proceeds of which were loaned to MidAmerican Energy for the purpose of constructing solid waste facilities. In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95%2.70% First Mortgage Bonds due August 2047. In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017. In December 2016, the Iowa Finance Authority issued $30 million of its variable-rate, tax-exempt Solid Waste Facilities Revenue Bonds due December 2046, the proceeds of which were loaned to MidAmerican Energy for the purpose of constructing solid waste facilities. In September 2016, the Iowa Finance Authority issued $33 million of variable-rate, tax-exempt Pollution Control Facilities Refunding Revenue Bonds due September 2036, the proceeds of which were loaned to MidAmerican Energy to refinance, in September 2016, variable-rate tax-exempt pollution control refunding revenue bonds totaling $29 million due September 2016 and $4 million due March 2017, which were optionally redeemed in full. Through its commercial paper program, MidAmerican Energy received $240 million in 2018, made repayments totaling $99 million in 2017 and received $99 million in 2016.
In December 2017, MidAmerican Funding redeemed through a tender offer a portion of its 6.927% Senior Bonds. MidAmerican Funding made payments totaling $8 million in 2018 and received $133 million and $9 million in 2017 and 2016, respectively, through its note payable with BHE.
2052. In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049.2049, and in October 2019, issued an additional $250 million of its 3.65% First Mortgage Bonds due April 2029 and $600 million of its 3.15% First Mortgage Bonds due April 2050. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest. Net (repayments of) proceeds from short-term debt relate to MidAmerican Energy's use of short-term borrowings through its commercial paper program. MidAmerican Funding received $12 million, $5 million and $15 million in 2021, 2020 and 2019, respectively, through its note payable with BHE.
Debt Authorizations and Related Matters
Short-term Debt
MidAmerican Energy has authority from the FERC to issue through July 31, 2020,April 2, 2022, commercial paper and bank notes aggregating $1.3$1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate ("LIBOR") plus a spread of 400 basis points. MidAmerican Energy has a $900 million$1.5 billion unsecured credit facility expiring in June 2021 with a one-year extension option subject to lender consent.2024. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities and preferred stock through June 26, 2021. Additionally,13, 2024. MidAmerican Energy has authorization from the FERC to issue, through August 31, 2019,June 30, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million and from the ICC to issue preferred stocklong-term debt securities up to an aggregate of $350 million through August 20, 2022. Additionally, MidAmerican Energy has authority from the ICC through October 15, 2024, to issue $750 million of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million through November 1, 2020.of its 2.40% Senior notes due October 2024.
MidAmerican Energy's mortgage dated September 9, 2013, creates a lien on most of MidAmerican Energy's electric utility property within the state of Iowa, allowing the issuance of bonds based on a percentage of eligible utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. As of December 31, 2021, MidAmerican Energy estimated it would be able to issue up to $8.1 billion of new first mortgage bonds under the mortgage. Any issuances are subject to market conditions, and amounts are further limited by regulatory authorizations and commitments, as well as any more restrictive requirements of covenants and tests contained in other financing agreements. MidAmerican Energy also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
MidAmerican Funding or one of its subsidiaries, including MidAmerican Energy, may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by MidAmerican Funding or one of its subsidiaries may be reissued or resold by MidAmerican Funding or one of its subsidiaries from time to time and will depend on prevailing market conditions, the issuing company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Future Uses of Cash
MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Wind generation | $ | 1,877 | | | $ | 911 | | | $ | 964 | | | $ | 792 | | | $ | 1,810 | | | $ | 1,741 | |
Electric distribution | 277 | | | 273 | | | 257 | | | 274 | | | 238 | | | 155 | |
Electric transmission | 177 | | | 160 | | | 199 | | | 173 | | | 85 | | | 83 | |
Solar generation | 2 | | | 16 | | | 132 | | | 93 | | | 58 | | | — | |
Other | 477 | | | 476 | | | 360 | | | 581 | | | 459 | | | 332 | |
Total | $ | 2,810 | | | $ | 1,836 | | | $ | 1,912 | | | $ | 1,913 | | | $ | 2,650 | | | $ | 2,311 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| | | | | | | | | | | |
Wind-powered generation development | $ | 943 |
| | $ | 657 |
| | $ | 1,261 |
| | $ | 1,378 |
| | $ | 479 |
| | $ | 7 |
|
Wind-powered generation repowering | 67 |
| | 514 |
| | 422 |
| | 168 |
| | 236 |
| | 576 |
|
Transmission Multi-Value Projects | 119 |
| | 21 |
| | 50 |
| | 2 |
| | — |
| | — |
|
Other | 507 |
| | 581 |
| | 599 |
| | 996 |
| | 722 |
| | 475 |
|
Total | $ | 1,636 |
| | $ | 1,773 |
| | $ | 2,332 |
| | $ | 2,544 |
| | $ | 1,437 |
| | $ | 1,058 |
|
MidAmerican Energy's historical and forecast capital expenditures includeprovided above consist of the following:
The•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction and acquisition of wind-powered generating facilities totaled $540 million for 2021, $848 million for 2020 and $1,486 million for 2019. MidAmerican Energy placed in-service 817294 MWs (nominal ratings) during 2018, 3342021, 729 MWs (nominal ratings) during 2017 and 600 MWs (nominal ratings) during 2016. MidAmerican Energy currently has two wind-powered generation construction projects in progress under ratemaking principles approved by the IUB.
In August 2016, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 2,000 MWs (nominal ratings) of additional wind-powered generating facilities ("Wind XI"),2020, including the additions in 2017acquisition of an existing 80-MW wind farm and 2018 and facilities expected to be placed in-service in1,019 MWs during 2019. Wind XI ratemaking principles established a cost cap of $3.6 billion, including AFUDC, and a fixed rate of return on equity of 11.0% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding. Additionally, the ratemaking principles modified the revenue sharing mechanism in effect prior to 2018. The revised sharing mechanism, which was effective for 2018, was triggered by MidAmerican Energy's actual equity return exceeding a weighted average return on equity of 10.7% for 2018. Pursuant to revenue sharing approved in the Wind XI order, MidAmerican Energy will share with customers 100% of the revenue in excess of this trigger, or $70 million for 2018. Such revenue sharing will reduce generation rate base, which is intended to mitigate future base rate increases.
In May 2018, MidAmerican Energy filed with the IUB an application for ratemaking principles related to the construction of up to 591 MWs (nominal ratings) of additional wind-powered generating facilities ("Wind XII") expected to be placed in-service by the end of 2020. The filing requested a cost cap of $922 million, including AFUDC, a fixed rate of return on equity of 11.25% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding, and no change to the Wind XI revenue sharing mechanism. In September 2018, MidAmerican Energy filed with the IUB a settlement agreement signed by a majority of the parties to the ratemaking principles proceeding for Wind XII. The settlement agreement, which was approved by the IUB in December 2018, retains the $922 million cost cap, establishes a fixed rate of return on equity of 11.0% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding and provides that all Iowa retail energy benefits from Wind XII will reduce rate base and be excluded from the Iowa energy adjustment clause. Additionally, the settlement agreement modifies the Wind XI revenue sharing mechanism, effective January 1, 2019, such that revenue sharing will be triggered each year by actual equity returns above a threshold calculated annually or 11%, whichever is less, and MidAmerican Energy will share with customers 90% of the revenue in excess of the trigger, instead of 100% sharing. The threshold will be calculated each year-end and will be the weighted average of equity returns authorized via ratemaking principles for certain rate base and, for remaining rate base, interest rates on 30-year single A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%.
The cost caps established by the Wind XI and Wind XII ratemaking principles ensure that as long as total costs for each project are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. MidAmerican Energy expects allAll of these wind-powered generating facilities toplaced in-service in 2021, 2020 and 2019 qualify for 100% of production tax creditsPTCs available.
The repowering of the oldest of MidAmerican Energy's wind-powered generating facilities in Iowa. Internal Revenue Service ("IRS") rules provide for re-establishment of the production tax credit for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement meets IRS guidelines, production tax credits PTCs from these projects are re-established for ten years at rates that depend upon the date in which construction begins. Repowered facilities placed in-service totaled 222 MWs and $203 million in 2018 and 414 MWs and $465 million in 2017. Under MidAmerican Energy's Iowa electric tariff, federal production tax credits related to facilities that were in-service prior to 2013 must be included in its Iowa energy adjustment clause. In August 2017, the IUB approved a tariff change that excludesexcluded from MidAmerican Energy's Iowa energy adjustment clause any future federal production tax credits relatedEAC until these generation assets are reflected in base rates.
◦Repowering of wind-powered generating facilities totaled $354 million for 2021, $37 million for 2020 and $369 million for 2019. Planned spending for repowering totals $509 million in 2022. MidAmerican Energy expects its repowered facilities to these repowered facilities. The energy productionmeet IRS guidelines for the re-establishment of PTCs for 10 years from the repowereddate the facilities are placed in-service as of December 31, 2018, is expected to qualifyin-service. The rate at which PTCs are re-established for 100% ofa facility depends upon the federal production tax credits available for ten years following each facility's return to service.date construction begins. Of the 1,615865 MWs of current repowering projects not in-service as of December 31, 2018, 4392021, 564 MWs are currently expected to qualify for 100%80% of the federal production tax creditsPTCs available for ten10 years following each facility's return to service 769 MWs are expected to qualify for 80% of such credits and 407301 MWs are expected to qualify for 60% of such credits.
Transmission MVP investments. In 2012, MidAmerican Energy started•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.
•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.
•Solar generation includes the construction of four MISO-approved MVPs locatedsolar-powered generating facilities totaling 141 MWs of small- and utility-scale solar generation, with total spend of $132 million in Iowa2021 and Illinois. When complete, the four MVPs will have added approximately 250 milesplanned spending of 345-kV transmission line to MidAmerican Energy's transmission system$93 million in 2022 and will be owned and operated by MidAmerican Energy. As of December 31, 2018, 224 miles of these MVP transmission lines have been placed in-service.$58 million in 2023.
•Remaining expenditures primarily relate to routine operating projects for other generation, natural gas distribution, generation, transmissiontechnology, facilities and other infrastructure neededoperational needs to serve existing and expected demand.
Contractual Obligations
Material Cash Requirements
MidAmerican Energy and MidAmerican Funding have contractual cash obligationsrequirements that may affect their financial condition. The following table summarizes the material contractual cash obligations of MidAmerican Energycondition that arise primarily from long- and MidAmerican Funding as of December 31, 2018 (in millions):
|
| | | | | | | | | | | | | | | | | | | |
| Payments Due By Periods | | |
| | | 2020- | | 2022- | | 2024 and | | |
| 2019 | | 2021 | | 2023 | | After | | Total |
MidAmerican Energy: | | | | | | | | | |
Long-term debt | $ | 500 |
| | $ | 2 |
| | $ | 315 |
| | $ | 4,611 |
| | $ | 5,428 |
|
Interest payments on long-term debt(1) (2) | 213 |
| | 415 |
| | 414 |
| | 3,070 |
| | 4,112 |
|
Coal, electricity and natural gas contract commitments(1) | 270 |
| | 227 |
| | 108 |
| | 66 |
| | 671 |
|
Construction commitments(1) | 1,299 |
| | 28 |
| | 50 |
| | — |
| | 1,377 |
|
Easements and operating leases(1) | 27 |
| | 58 |
| | 60 |
| | 1,078 |
| | 1,223 |
|
Other commitments(1) | 118 |
| | 343 |
| | 277 |
| | 224 |
| | 962 |
|
| 2,427 |
| | 1,073 |
| | 1,224 |
| | 9,049 |
| | 13,773 |
|
| | | | | | | | | |
MidAmerican Funding parent: | | | | | | | | | |
Long-term debt | — |
| | — |
| | — |
| | 239 |
| | 239 |
|
Interest payments on long-term debt(1) | 17 |
| | 33 |
| | 33 |
| | 91 |
| | 174 |
|
| 17 |
| | 33 |
| | 33 |
| | 330 |
| | 413 |
|
Total contractual cash obligations | $ | 2,444 |
| | $ | 1,106 |
| | $ | 1,257 |
| | $ | 9,379 |
| | $ | 14,186 |
|
| |
(1) | Not reflected on the Consolidated Balance Sheets. |
| |
(2) | Includes interest payments for tax-exempt bond obligations with interest rates scheduled to reset periodically prior to maturity. Future variable interest rates are assumed to equal December 31, 2018 rates. |
MidAmerican Energy has other types of commitments that relate primarily to construction expenditures (in "Capital Expenditures" section above) and asset retirement obligations beyond 2018 (Note 11), which have not been included in the above table because the amount or timing of the cash payments is not certain. Refershort-term debt (refer to Notes 8, 117 and 138), firm commitments (refer to Note 13) and construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7) and AROs (refer to Note 11). Refer, where applicable, to the respective referenced note in Notes to Financial Statements in Item 8 of this Form 10-K for additional information.
MidAmerican Energy has cash requirements relating to interest payments of $5.6 billion on long-term debt, including $303 million due in 2022. Additionally, MidAmerican Funding has cash requirements relating to interest payments on its long-term debt of $124 million, including $17 million due in 2022.
Regulatory Matters
MidAmerican Energy is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussioninformation regarding MidAmerican Energy's general regulatory framework and current regulatory matters.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, ("which was a subsidiary of Exelon Generation")Corporation prior to February 1, 2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018, as a result of Illinois not passing adequate legislation and Quad Cities Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating license in 2032 and worked with Exelon Generation on solutions to that end.2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZEC's")ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission creditsZECs will provide Exelon GenerationConstellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. For the nuclear assets already in rate base, MidAmerican Energy's customers will not be charged for the subsidy, and MidAmerican Energy will not receive additional revenue from the subsidy.
On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of IllinoisThe PJM Interconnection, L.L.C. ("Northern District of Illinois"PJM") against the Illinois Power Agency alleging that the state's zero emission credit program violates certain provisions of the United States Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC's energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, Exelon Generation intervened and filed motions to dismiss in both lawsuits. On July 14, 2017, the Northern District of Illinois granted the motions to dismiss. On July 17, 2017, the plaintiffs filed appeals with the United States Court of Appeals for the Seventh Circuit ("Seventh Circuit"). On May 29, 2018, the United States Department of Justice and the FERC filed an amicus brief arguing federal rules do not preempt Illinois' ZEC program. On September 13, 2018, the Seventh Circuit upheld the Northern District of Illinois' ruling concluding that Illinois' ZEC program does not violate the Federal Power Act, and is thus, constitutional. On January 7, 2019, plaintiffs filedincludes a petition seeking review of the case by the United States Supreme Court.
On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions. If a generation resource is subjected to applya MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources receiving zero emission credit compensation. If successful, an expanded MOPR could resultwould require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the facility. 2022-2023 planning year in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As majority owner and operator ofa result, the MOPR applied to Quad Cities Station Exelon Generation hasin the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed protestsrelated tariff revisions at the FERC in responseon July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to each filing. The timingQuad Cities Station. Requests for rehearing of the FERC's decision with respectnotice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to both proceedings is currently unknown andbe at heightened risk for early retirement. However, to the outcomeextent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of these matters is currently uncertain.the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt securities of MidAmerican Energy are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of MidAmerican Energy's ability to, in general, meet the obligations of its issued debt securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2018,2021, MidAmerican Energy's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the three recognized credit rating agencies were investment grade. As a result of the issuance of first mortgage bonds by MidAmerican Energy in September 2013, its then outstanding senior unsecured debt was equally and ratably secured with such first mortgage bonds. Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for a discussion of MidAmerican Energy's first mortgage bonds.
MidAmerican Funding and MidAmerican Energy have no credit rating downgrade triggers that would accelerate the maturity dates of its outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. MidAmerican Energy's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base MidAmerican Energy's collateral requirements on its credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in MidAmerican Energy's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2018,2021, MidAmerican Energy would have been required to post $106$60 million of additional collateral. MidAmerican Energy's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where MidAmerican Energy operates have not had a significant impact on its financial results. MidAmerican Energy operates under cost-of-service based rate structures administered by various state commissions and the FERC. Under these rate structures, MidAmerican Energy is allowed to include prudent costs in its rates, including the impact of inflation. MidAmerican Energy attempts to minimize the potential impact of inflation on its operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, inflation's impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs, and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting MidAmerican Energy and MidAmerican Funding, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by MidAmerican Energy's methods, judgments and assumptions used in the preparation of the Financial Statements and should be read in conjunction with MidAmerican Energy's Summary of Significant Accounting Policies included in Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
MidAmerican Energy continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition, that could limit MidAmerican Energy's ability to recover its costs. MidAmerican Energy believes the application of the guidance for regulated operations is appropriate, and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").AOCI. Total regulatory assets were $273$473 million and total regulatory liabilities were $1,620$1,080 million as of December 31, 2018.2021. Refer to Note 5 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding regulatory assets and liabilities.
Income Taxes
In determining MidAmerican Funding's and MidAmerican Energy's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by MidAmerican Energy's various regulatory commissions. MidAmerican Funding's and MidAmerican Energy's income tax returns are subject to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of their federal, state and local tax examinations is uncertain, each company believes it has made adequate provisions for its income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on its consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding income taxes.
It is probable that MidAmerican Energy will passeither refund to, or recover from its customers in certain state jurisdiction income tax benefits and expensesexpense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences, and other various differences on to its customers.differences. As of December 31, 2018,2021, these amounts were recognized as a net regulatory liability of $626$83 million and will be included in regulated rates when the associated temporary differences reverse.
Impairment of Goodwill
MidAmerican Funding's Consolidated Balance Sheet as of December 31, 2018,2021, includes goodwill from the acquisition of MHC totaling $1.3 billion. Goodwill is allocated to each reporting unit. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2018.2021. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MidAmerican Funding uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, MidAmerican Funding incorporates current market information, as well as historical factors.
Pension and Other Postretirement Benefits
MidAmerican Energy sponsors defined benefit pension and other postretirement benefit plans that cover the majority of the employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy Inc. MidAmerican Energy recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2018,2021, MidAmerican Energy recognized a net liability totaling $87$54 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2018,2021, amounts not yet recognized as a component of net periodic benefit cost that were included in regulatory assets and regulatory liabilities totaled $62 million.$42 million and $55 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. MidAmerican Energy believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for disclosures about MidAmerican Energy's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2018.2021.
MidAmerican Energy chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to cash flows over the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, MidAmerican Energy utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. MidAmerican Energy regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
MidAmerican Energy chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5%5.00% by 2025 at which point the rate of increase is assumed to remain constant. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Financial Statements of the total plan before allocations to affiliates would be as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| +0.5% | | -0.5% | | +0.5% | | -0.5% |
Effect on December 31, 2021 Benefit Obligations: | | | | | | | |
Discount rate | $ | (38) | | | $ | 45 | | | $ | (13) | | | $ | 15 | |
| | | | | | | |
Effect on 2021 Periodic Cost: | | | | | | | |
Discount rate | 1 | | | — | | | — | | | 1 | |
Expected rate of return on plan assets | (3) | | | 3 | | | (1) | | | 1 | |
|
| | | | | | | | | | | | | | | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| +0.5% | | -0.5% | | +0.5% | | -0.5% |
Effect on December 31, 2018 Benefit Obligations: | | | | | | | |
Discount rate | $ | (34 | ) | | $ | 37 |
| | $ | (9 | ) | | $ | 10 |
|
| | | | | | | |
Effect on 2018 Periodic Cost: | | | | | | | |
Discount rate | 2 |
| | (2 | ) | | — |
| | — |
|
Expected rate of return on plan assets | (3 | ) | | 3 |
| | (1 | ) | | 1 |
|
A variety of factors affect the funded status of the plans, including asset returns, discount rates, plan changes and MidAmerican Energy's funding policy for each plan.
Revenue Recognition - Unbilled Revenue
Revenue from electric and natural gas customers is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of customer meters and applicable rates. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $88$85 million as of December 31, 2018.2021. Factors that can impact the estimate of unbilled energyrevenue include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month, and billed revenue is recorded based on the subsequent meter readings.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
MidAmerican Energy's Balance Sheets include assets and liabilities with fair values that are subject to market risks. MidAmerican Energy's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which it transacts. The following discussion addresses the significant market risks associated with MidAmerican Energy's business activities. MidAmerican Energy has established guidelines for credit risk management. Refer to Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's contracts accounted for as derivatives.
Commodity Price Risk
MidAmerican Energy is exposed to the impact of market fluctuations in commodity prices and interest rates. MidAmerican Energy is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territory. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather; market liquidity; generating facility availability; customer usage; storage; and transmission and transportation constraints. Commodity price risk for MidAmerican Energy's regulated retail electricity and natural gas operations is significantly mitigated by the inclusion of energy costs in energy cost rider mechanisms, which permit the current recovery of such costs from its retail customers. MidAmerican Energy uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements to mitigate price volatility on behalf of its customers. MidAmerican Energy does not engage in a material amount of proprietary trading activities, and following the January 1, 2016 transfer of MidAmerican Energy's unregulated retail services business to a subsidiary of BHE, MidAmerican Energy no longer provides nonregulated retail electricity and natural gas services in competitive markets.activities.
Interest Rate Risk
MidAmerican Energy and MidAmerican Funding are exposed to interest rate risk on their outstanding variable-rate short- and long-term debt and future debt issuances. MidAmerican Energy and MidAmerican Funding manage interest rate risk by limiting their exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the fixed-rate long-term debt does not expose MidAmerican Energy or MidAmerican Funding to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if MidAmerican Energy or MidAmerican Funding were to reacquire all or a portion of these instruments prior to their maturity. MidAmerican Energy or MidAmerican Funding may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate their exposure to interest rate risk. The nature and amount of their short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7, 8 and 12 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-K for additional discussion of MidAmerican Energy's and MidAmerican Funding's short- and long-term debt.
As of December 31, 20182021 and 2017,2020, MidAmerican Energy had short- and long-term variable-rate obligations totaling $610 million and $370 million respectively, that expose MidAmerican Energy to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to MidAmerican Energy's variable-rate debt as of December 31, 2018,2021, is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on MidAmerican Energy's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 20182021 and 2017.2020.
Credit Risk
MidAmerican Energy is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Additionally, MidAmerican Energy participates in the regional transmission organization ("RTO")RTO markets and has indirect credit exposure related to other participants, although RTO credit policies are designed to limit exposure to credit losses from individual participants. Credit risk may be concentrated to the extent MidAmerican Energy's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MidAmerican Energy analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty, and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MidAmerican Energy enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MidAmerican Energy exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2018,2021, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
266
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Item 8. | Financial Statements and Supplementary Data |
Item 8.Financial Statements and Supplementary Data
MidAmerican Energy Company
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Balance Sheets | |
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Statements of Operations | |
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MidAmerican Funding, LLC and Subsidiaries
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
MidAmerican Energy Company
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying balance sheets of MidAmerican Energy Company ("MidAmerican Energy") as of December 31, 20182021 and 2017,2020, the related statements of operations, comprehensive income, changes in shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2018,2021, and the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MidAmerican Energy as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of MidAmerican Energy's management. Our responsibility is to express an opinion on MidAmerican Energy's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MidAmerican Energy is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MidAmerican Energy's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 5 to the financial statements
Critical Audit Matter Description
MidAmerican Energy is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where MidAmerican Energy operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense and income tax benefit.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow MidAmerican Energy an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While MidAmerican Energy has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit MidAmerican Energy's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated MidAmerican Energy's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected MidAmerican Energy's filings with the Commissions and the filings with the Commissions by intervenors that may impact MidAmerican Energy's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
February 22, 201925, 2022
We have served as MidAmerican Energy's auditor since 1999.
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
| | | |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 232 | | | $ | 38 | |
Trade receivables, net | 526 | | | 234 | |
Income tax receivable | 79 | | | — | |
Inventories | 234 | | | 278 | |
Other current assets | 123 | | | 73 | |
Total current assets | 1,194 | | | 623 | |
| | | |
Property, plant and equipment, net | 20,301 | | | 19,279 | |
Regulatory assets | 473 | | | 392 | |
Investments and restricted investments | 1,026 | | | 911 | |
Other assets | 263 | | | 232 | |
| | | |
Total assets | $ | 23,257 | | | $ | 21,437 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | — |
| | $ | 172 |
|
Accounts receivable, net | 367 |
| | 344 |
|
Income taxes receivable | — |
| | 51 |
|
Inventories | 204 |
| | 245 |
|
Other current assets | 90 |
| | 134 |
|
Total current assets | 661 |
| | 946 |
|
| | | |
Property, plant and equipment, net | 16,159 |
| | 14,207 |
|
Regulatory assets | 273 |
| | 204 |
|
Investments and restricted investments | 708 |
| | 728 |
|
Other assets | 119 |
| | 233 |
|
| | | |
Total assets | $ | 17,920 |
| | $ | 16,318 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 531 | | | $ | 408 | |
Accrued interest | 84 | | | 78 | |
Accrued property, income and other taxes | 158 | | | 161 | |
| | | |
| | | |
Other current liabilities | 145 | | | 183 | |
Total current liabilities | 918 | | | 830 | |
| | | |
Long-term debt | 7,721 | | | 7,210 | |
Regulatory liabilities | 1,080 | | | 1,111 | |
Deferred income taxes | 3,389 | | | 3,054 | |
Asset retirement obligations | 714 | | | 709 | |
Other long-term liabilities | 475 | | | 458 | |
Total liabilities | 14,297 | | | 13,372 | |
| | | |
Commitments and contingencies (Note 13) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 561 | | | 561 | |
Retained earnings | 8,399 | | | 7,504 | |
| | | |
Total shareholder's equity | 8,960 | | | 8,065 | |
| | | |
Total liabilities and shareholder's equity | $ | 23,257 | | | $ | 21,437 | |
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| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 575 |
| | $ | 452 |
|
Accrued interest | 53 |
| | 48 |
|
Accrued property, income and other taxes | 300 |
| | 132 |
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Short-term debt | 240 |
| | — |
|
Current portion of long-term debt | 500 |
| | 350 |
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Other current liabilities | 122 |
| | 128 |
|
Total current liabilities | 1,790 |
| | 1,110 |
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| | | |
Long-term debt | 4,881 |
| | 4,692 |
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Regulatory liabilities | 1,620 |
| | 1,661 |
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Deferred income taxes | 2,322 |
| | 2,237 |
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Asset retirement obligations | 552 |
| | 528 |
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Other long-term liabilities | 309 |
| | 326 |
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Total liabilities | 11,474 |
| | 10,554 |
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Commitments and contingencies (Note 13) |
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| | | |
Shareholder's equity: | | | |
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — |
| | — |
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Additional paid-in capital | 561 |
| | 561 |
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Retained earnings | 5,885 |
| | 5,203 |
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Total shareholder's equity | 6,446 |
| | 5,764 |
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| | | |
Total liabilities and shareholder's equity | $ | 17,920 |
| | $ | 16,318 |
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The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,529 | | | $ | 2,139 | | | $ | 2,237 | |
Regulated natural gas and other | 1,018 | | | 581 | | | 688 | |
Total operating revenue | 3,547 | | | 2,720 | | | 2,925 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 539 | | | 339 | | | 399 | |
Cost of natural gas purchased for resale and other | 761 | | | 328 | | | 413 | |
Operations and maintenance | 775 | | | 754 | | | 800 | |
Depreciation and amortization | 914 | | | 716 | | | 639 | |
Property and other taxes | 142 | | | 135 | | | 126 | |
Total operating expenses | 3,131 | | | 2,272 | | | 2,377 | |
| | | | | |
Operating income | 416 | | | 448 | | | 548 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (302) | | | (304) | | | (281) | |
Allowance for borrowed funds | 13 | | | 15 | | | 27 | |
Allowance for equity funds | 39 | | | 45 | | | 78 | |
Other, net | 53 | | | 52 | | | 50 | |
Total other income (expense) | (197) | | | (192) | | | (126) | |
| | | | | |
Income before income tax benefit | 219 | | | 256 | | | 422 | |
Income tax benefit | (675) | | | (570) | | | (371) | |
| | | | | |
Net income | $ | 894 | | | $ | 826 | | | $ | 793 | |
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| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,283 |
| | $ | 2,108 |
| | $ | 1,985 |
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Regulated natural gas and other | 766 |
| | 729 |
| | 640 |
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Total operating revenue | 3,049 |
| | 2,837 |
| | 2,625 |
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| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 487 |
| | 434 |
| | 409 |
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Cost of natural gas purchased for resale and other | 466 |
| | 442 |
| | 367 |
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Operations and maintenance | 811 |
| | 799 |
| | 708 |
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Depreciation and amortization | 609 |
| | 500 |
| | 479 |
|
Property and other taxes | 125 |
| | 119 |
| | 112 |
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Total operating expenses | 2,498 |
| | 2,294 |
| | 2,075 |
|
| | | | | |
Operating income | 551 |
| | 543 |
| | 550 |
|
| | | | | |
Other income (expense): | | | | | |
Interest expense | (227 | ) | | (214 | ) | | (196 | ) |
Allowance for borrowed funds | 20 |
| | 15 |
| | 8 |
|
Allowance for equity funds | 53 |
| | 41 |
| | 19 |
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Other, net | 30 |
| | 37 |
| | 29 |
|
Total other income (expense) | (124 | ) | | (121 | ) | | (140 | ) |
| | | | | |
Income before income tax benefit | 427 |
| | 422 |
| | 410 |
|
Income tax benefit | (255 | ) | | (183 | ) | | (132 | ) |
| | | | | |
Net income | $ | 682 |
| | $ | 605 |
| | $ | 542 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 682 |
| | $ | 605 |
| | $ | 542 |
|
| | | | | |
Other comprehensive income, net of tax: | | | | | |
Unrealized gains on marketable securities, net of tax of $-, $- and $1 | — |
| | — |
| | 3 |
|
| | | | | |
Comprehensive income | $ | 682 |
| | $ | 605 |
| | $ | 545 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Additional | | | | Total |
| Common | | Paid-in | | Retained | | Shareholder's |
| Stock | | Capital | | Earnings | | Equity |
| | | | | | | |
Balance, December 31, 2018 | $ | — | | | $ | 561 | | | $ | 5,885 | | | $ | 6,446 | |
Net income | — | | | — | | | 793 | | | 793 | |
Other equity transactions | — | | | — | | | 1 | | | 1 | |
Balance, December 31, 2019 | — | | | 561 | | | 6,679 | | | 7,240 | |
Net income | — | | | — | | | 826 | | | 826 | |
Other equity transactions | — | | | — | | | (1) | | | (1) | |
| | | | | | | |
Balance, December 31, 2020 | — | | | 561 | | | 7,504 | | | 8,065 | |
Net income | — | | | — | | | 894 | | | 894 | |
| | | | | | | |
Other equity transactions | — | | | — | | | 1 | | | 1 | |
Balance, December 31, 2021 | $ | — | | | $ | 561 | | | $ | 8,399 | | | $ | 8,960 | |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | Accumulated | | |
| | | Additional | | | | Other | | Total |
| Common | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| Stock | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | |
Balance, December 31, 2015 | $ | — |
| | $ | 561 |
| | $ | 4,174 |
| | $ | (30 | ) | | $ | 4,705 |
|
Net income | — |
| | — |
| | 542 |
| | — |
| | 542 |
|
Other comprehensive income | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Dividend of unregulated retail services business | — |
| | — |
| | (117 | ) | | 27 |
| | (90 | ) |
Balance, December 31, 2016 | — |
| | 561 |
| | 4,599 |
| | — |
| | 5,160 |
|
Net income | — |
| | — |
| | 605 |
| | — |
| | 605 |
|
Other equity transactions | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Balance, December 31, 2017 | — |
| | 561 |
| | 5,203 |
| | — |
| | 5,764 |
|
Net income | — |
| | — |
| | 682 |
| | — |
| | 682 |
|
Balance, December 31, 2018 | $ | — |
| | $ | 561 |
| | $ | 5,885 |
| | $ | — |
| | $ | 6,446 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 894 | | | $ | 826 | | | $ | 793 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
Depreciation and amortization | 914 | | | 716 | | | 639 | |
Amortization of utility plant to other operating expenses | 34 | | | 34 | | | 33 | |
Allowance for equity funds | (39) | | | (45) | | | (78) | |
Deferred income taxes and amortization of investment tax credits | 153 | | | 208 | | | 154 | |
| | | | | |
Settlements of asset retirement obligations | (103) | | | (124) | | | (14) | |
Other, net | 21 | | | (18) | | | 4 | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | (293) | | | 48 | | | 60 | |
Inventories | 44 | | | (52) | | | (22) | |
| | | | | |
Pension and other postretirement benefit plans, net | (4) | | | (19) | | | (10) | |
Accrued property, income and other taxes, net | (71) | | | (64) | | | (76) | |
Accounts payable and other liabilities | 67 | | | 33 | | | 7 | |
Net cash flows from operating activities | 1,617 | | | 1,543 | | | 1,490 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (1,912) | | | (1,836) | | | (2,810) | |
Purchases of marketable securities | (213) | | | (281) | | | (156) | |
Proceeds from sales of marketable securities | 207 | | | 269 | | | 138 | |
Proceeds from sales of other investments | — | | | 2 | | | 1 | |
Other investment proceeds | 1 | | | 9 | | | 13 | |
Other, net | 6 | | | 11 | | | 13 | |
Net cash flows from investing activities | (1,911) | | | (1,826) | | | (2,801) | |
| | | | | |
Cash flows from financing activities: | | | | | |
| | | | | |
Proceeds from long-term debt | 492 | | | — | | | 2,326 | |
Repayments of long-term debt | (1) | | | — | | | (500) | |
Net repayments of short-term debt | — | | | — | | | (240) | |
Other, net | (3) | | | (2) | | | (1) | |
Net cash flows from financing activities | 488 | | | (2) | | | 1,585 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 194 | | | (285) | | | 274 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of year | 45 | | | 330 | | | 56 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of year | $ | 239 | | | $ | 45 | | | $ | 330 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Cash flows from operating activities: | | | | | |
Net income | $ | 682 |
| | $ | 605 |
| | $ | 542 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
Depreciation and amortization | 609 |
| | 500 |
| | 479 |
|
Amortization of utility plant to other operating expenses | 34 |
| | 34 |
| | 37 |
|
Allowance for equity funds | (53 | ) | | (41 | ) | | (19 | ) |
Deferred income taxes and amortization of investment tax credits | 33 |
| | 332 |
| | 361 |
|
Other, net | 13 |
| | (15 | ) | | (62 | ) |
Changes in other operating assets and liabilities: | | | | | |
Accounts receivable and other assets | (25 | ) | | (60 | ) | | (60 | ) |
Inventories | 41 |
| | 19 |
| | (27 | ) |
Derivative collateral, net | (1 | ) | | 2 |
| | 5 |
|
Contributions to pension and other postretirement benefit plans, net | (13 | ) | | (11 | ) | | (6 | ) |
Accrued property, income and other taxes, net | 218 |
| | (41 | ) | | 107 |
|
Accounts payable and other liabilities | (30 | ) | | 72 |
| | 46 |
|
Net cash flows from operating activities | 1,508 |
| | 1,396 |
| | 1,403 |
|
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (2,332 | ) | | (1,773 | ) | | (1,636 | ) |
Purchases of marketable securities | (263 | ) | | (143 | ) | | (138 | ) |
Proceeds from sales of marketable securities | 223 |
| | 137 |
| | 158 |
|
Proceeds from sales of other investments | 17 |
| | 2 |
| | — |
|
Other investment proceeds | 15 |
| | 1 |
| | — |
|
Other, net | 30 |
| | — |
| | 11 |
|
Net cash flows from investing activities | (2,310 | ) | | (1,776 | ) | | (1,605 | ) |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 687 |
| | 990 |
| | 62 |
|
Repayments of long-term debt | (350 | ) | | (255 | ) | | (38 | ) |
Net proceeds from (repayments of) short-term debt | 240 |
| | (99 | ) | | 99 |
|
Other, net | (1 | ) | | — |
| | — |
|
Net cash flows from financing activities | 576 |
| | 636 |
| | 123 |
|
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (226 | ) | | 256 |
| | (79 | ) |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of year | 282 |
| | 26 |
| | 105 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of year | $ | 56 |
| | $ | 282 |
| | $ | 26 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
| |
(1) | Organization and Operations
|
(1)Organization and Operations
MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries and related corporate services.subsidiaries. MHC's nonregulated subsidiaries includesubsidiary is Midwest Capital Group, Inc. and MEC Construction Services Co. MHC is the direct wholly owned subsidiary of MidAmerican Funding, LLC, ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
| |
(2) | Summary of Significant Accounting Policies
|
(2)Summary of Significant Accounting Policies
Basis ofPresentation
The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Financial Statements.
Accounting for the Effects of Certain Types of Regulation
MidAmerican Energy's utility operations are subject to the regulation of the Iowa Utilities Board ("IUB"), the Illinois Commerce Commission ("ICC"), the South Dakota Public Utilities Commission, and the Federal Energy Regulatory Commission ("FERC"). MidAmerican Energy's accounting policies and the accompanying Financial Statements conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the ratemaking process.
MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
MidAmerican Energy continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition, that could limit MidAmerican Energy's ability to recover its costs. MidAmerican Energy believes the application of the guidance for regulated operations is appropriate, and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents is comprised of funds restricted for the purpose of constructing solid waste facilities under tax exempt bond agreements. Restricted amounts are included in other current assets and investments and restricted investments on the Balance Sheets.
Investments
Fixed Maturity Securities
MidAmerican Energy's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Balance Sheets.
Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of the Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") are recorded as a net regulatory liability because MidAmerican Energy expects to recoverrefund to customers any decommissioning funds in excess of costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity securities are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.
Investments gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if MidAmerican Energy intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If MidAmerican Energy does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.
Equity Securities
All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since MidAmerican Energy expects to recoverrefund to customers any decommissioning funds in excess of costs for these activities through regulated rates.
Allowance for Doubtful AccountsCredit Losses
ReceivablesTrade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts.credit losses. The allowance for doubtful accountscredit losses is based on MidAmerican Energy's assessment of the collectibilitycollectability of amounts owed to it by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. As of December 31, 2018 and 2017,In measuring the allowance for doubtful accounts totaled $7 millioncredit losses for trade receivables, MidAmerican Energy primarily utilizes credit loss history. However, it may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Balance Sheets.Sheets, is summarized as follows for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 12 | | | $ | 5 | | | $ | 7 | |
Charged to operating costs and expenses, net | 10 | | | 12 | | | 9 | |
Write-offs, net | (10) | | | (5) | | | (11) | |
Ending balance | $ | 12 | | | $ | 12 | | | $ | 5 | |
Derivatives
MidAmerican Energy employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities, and interest rate risk. Derivative contracts are recorded on the Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Balance Sheets.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked to market, and settled amounts are recognized as operating revenue or cost of sales on the Statements of Operations.
For MidAmerican Energy's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.
Inventories
Inventories consist mainly of coal stocks,materials and supplies, totaling $51$135 million and $117$129 million as of December 31, 20182021 and 2017,2020, respectively, materials and supplies,coal stocks, totaling $124$63 million and $100$119 million as of December 31, 20182021 and 2017,2020, respectively, and natural gas in storage, totaling $24$30 million and $26 million as of December 31, 20182021 and 2017.2020, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined using the average cost method. The cost of stored natural gas is determined using the last-in-first-out method. With respect to stored natural gas, the replacement cost would be $14$27 million and $22$10 million higher as of December 31, 20182021 and 2017,2020, respectively.
UtilityProperty, Plant and Equipment, Net
General
Additions to utility plant are recorded at cost. MidAmerican Energy capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC") and equity AFUDC. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds and retail energy benefits associated with certain wind-powered generation. Amounts expensed under this arrangementthese arrangements are included as a component of depreciation and amortization.
Depreciation and amortization for MidAmerican Energy's utility operations are computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by its various regulatory authorities. Depreciation studies are completed by MidAmerican Energy to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally, when MidAmerican Energy retires or sells a component of utility plant, it charges the original cost, net of any proceeds from the disposition to accumulated depreciation. Any gain or loss on disposals of nonregulated assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of its regulated facilities, is capitalized by MidAmerican Energy as a component of utility plant, with offsetting credits to the Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, MidAmerican Energy is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
MidAmerican Energy recognizes AROs when it has a legal obligation to perform decommissioning or removal activities upon retirement of an asset. MidAmerican Energy's AROs are primarily related to decommissioning of the Quad Cities Station and obligations associated with its other generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to utility plant) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in utility plant, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
MidAmerican Energy evaluates long-lived assets for impairment, including utility plant, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. For all other assets, any resulting impairment loss is reflected on the Statements of Operations.
Revenue Recognition
MidAmerican Energy uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which MidAmerican Energy expects to be entitled in exchange for those goods and services. MidAmerican Energy records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Statements of Operations.
A majority of MidAmerican Energy's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification ("ASC") 840, "Leases" and amounts not considered Customer Revenue within ASC 606.
Revenue from electric and natural gas customers is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 20182021 and 2017,2020, unbilled revenue was $88$85 million and $89$95 million, respectively, and is included in trade receivables, net on the Balance Sheets.
The determination of customer billings is based on a systematic reading of customer meters and applicable rates. At the end of each month, amounts of energy provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energyrevenue include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses economic impacts and composition of customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.
All of MidAmerican Energy's regulated retail electric and natural gas sales are subject to energy adjustment clauses. MidAmerican Energy also has costs that are recovered, at least in part, through bill riders, including demand-side management and certain transmission costs. The clauses and riders allow MidAmerican Energy to adjust the amounts charged for electric and natural gas service as the related costs change. The costs recovered in revenue through use of the adjustment clauses and bill riders are charged to expense in the same year the related revenue is recognized. At any given time, these costs may be over or under collected from customers. The total under collection included in trade receivables, net at December 31, 20182021 and 2017,2020, was $56$230 million and $72$22 million, respectively.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Berkshire Hathaway includes MidAmerican Funding and MidAmerican Energy in its consolidated United States federal and Iowa state income tax returns. MidAmerican Funding's and MidAmerican Energy's provisions for income taxes have been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimatedenacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that MidAmerican Energy deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
In determining MidAmerican Funding'sInvestment tax credits are generally deferred and MidAmerican Energy's income taxes, management is required to interpret complex income tax laws and regulations, which includes considerationamortized over the estimated useful lives of regulatory implications imposedthe related properties or as prescribed by MidAmerican Energy's various regulatory commissions. MidAmerican Funding's and MidAmerican Energy's income tax returns are subject to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved.
MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of their federal, state and local income tax examinations is uncertain, each company believes it has made adequate provisions for its income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on its consolidated financial results. MidAmerican Funding's and MidAmerican Energy's unrecognized tax benefits are primarily included in taxes accrued and other long-term liabilities on their respective Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
New Accounting Pronouncements
In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-14, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments in this guidance remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures and add disclosure requirements identified as relevant. The updated disclosure requirements make a number of changes to improve the effectiveness of disclosures in the notes to the financial statements. This guidance is effective for annual reporting periods ending after December 15, 2020, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy elected to early adopt ASU No. 2018-14 for period ending December 31, 2018. The adoption did not have a material impact on MidAmerican Energy's Financial Statements and disclosures included within Notes to Financial Statements.
In March 2017, the FASB issued ASU No. 2017-07, which amends FASB ASC Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. MidAmerican Energy adopted this guidance January 1, 2018 prospectively for the capitalization of the service cost component in the Balance Sheets and retrospectively for the presentation of the service cost component and the other components of net benefit cost in the Statements of Operations applying the practical expedient to use the amounts previously disclosed in the Notes to Financial Statements as the estimation basis for applying the retrospective presentation requirement. As a result, for the years ended December 31, 2017 and 2016, amounts other than the service cost for pension and other postretirement benefit plans totaling $20 million and $15 million, respectively, have been reclassified to Other, net in the Statements of Operations of participating subsidiaries, of which $18 million and $15 million, respectively, relates to MidAmerican Energy.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. MidAmerican Energy adopted this guidance effective January 1, 2018, and the adoption did not have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. MidAmerican Energy adopted this guidance effective January 1, 2018, and the adoption did not have a material impact on its Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases," ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption and ASU No. 2018-20 that provides targeted improvements to lessor accounting, such as the handling of sales and other similar taxes. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. MidAmerican Energy adopted this guidance effective January 1, 2019, for all contracts currently in-effect. MidAmerican Energy is finalizing its implementation efforts relative to the new guidance and currently does not believe the adoption of the new guidance will have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.
In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. MidAmerican Energy adopted this guidance effective January 1, 2018, and the adoption did not have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue"). The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. MidAmerican Energy adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.
(3)Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
| | | | | |
Utility plant in-service, net: | | | | | |
Generation | 20-70 years | | $ | 17,397 | | | $ | 16,980 | |
Transmission | 52-75 years | | 2,474 | | | 2,365 | |
Electric distribution | 20-75 years | | 4,661 | | | 4,369 | |
Natural gas distribution | 29-75 years | | 2,039 | | | 1,955 | |
Utility plant in-service | | | 26,571 | | | 25,669 | |
Accumulated depreciation and amortization | | | (7,376) | | | (6,902) | |
Utility plant in-service, net | | | 19,195 | | | 18,767 | |
Nonregulated property, net: | | | | | |
Nonregulated property gross | 20-50 years | | 7 | | | 7 | |
Accumulated depreciation and amortization | | | (1) | | | (1) | |
Nonregulated property, net | | | 6 | | | 6 | |
| | | 19,201 | | | 18,773 | |
Construction work-in-progress | | | 1,100 | | | 506 | |
Property, plant and equipment, net | | | $ | 20,301 | | | $ | 19,279 | |
|
| | | | | | | | | |
| Depreciable Life | | 2018 | | 2017 |
| | | | | |
Utility plant in service: | | | | | |
Generation | 20-70 years | | $ | 13,727 |
| | $ | 12,107 |
|
Transmission | 52-75 years | | 1,934 |
| | 1,838 |
|
Electric distribution | 20-75 years | | 3,672 |
| | 3,380 |
|
Natural gas distribution | 29-75 years | | 1,726 |
| | 1,640 |
|
Utility plant in service | | | 21,059 |
| | 18,965 |
|
Accumulated depreciation and amortization | | | (5,941 | ) | | (5,561 | ) |
Utility plant in service, net | | | 15,118 |
| | 13,404 |
|
Nonregulated property, net: | | | | | |
Nonregulated property gross | 20-50 years | | 7 |
| | 7 |
|
Accumulated depreciation and amortization | | | (1 | ) | | (1 | ) |
Nonregulated property, net | | | 6 |
| | 6 |
|
| | | 15,124 |
| | 13,410 |
|
Construction work-in-progress | | | 1,035 |
| | 797 |
|
Property, plant and equipment, net | | | $ | 16,159 |
| | $ | 14,207 |
|
Nonregulated property, includesnet consists primarily of land computer software and other assets not recoverable for regulated utility purposes.
The average depreciation and amortization rates applied to depreciable utility plant for the years ended December 31 were as follows:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Electric | 3.3 | % | | 3.2 | % | | 3.1 | % |
Natural gas | 2.8 | % | | 2.8 | % | | 2.8 | % |
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Electric | 2.9 | % | | 2.6 | % | | 2.8 | % |
Natural gas | 2.8 | % | | 2.7 | % | | 2.9 | % |
During the fourth quarter of 2016, MidAmerican Energy revised its electric and natural gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was longer estimated useful lives for certain wind-powered generating facilities. The effect of this change was to reduce depreciation and amortization expense by $3 million in 2016 and $34 million annually based on depreciable plant balances at the time of the change.
(4)Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, MidAmerican Energy, as a tenant in common, has undivided interests in jointly owned generation and transmission facilities. MidAmerican Energy accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating expenses on the Statements of Operations include MidAmerican Energy's share of the expenses of these facilities.
The amounts shown in the table below represent MidAmerican Energy's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 20182021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | Construction |
| Company | | Plant in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Louisa Unit No. 1 | 88 | % | | $ | 864 | | | $ | 501 | | | $ | 20 | |
Quad Cities Unit Nos. 1 & 2(1) | 25 | | | 732 | | | 452 | | | 9 | |
Walter Scott, Jr. Unit No. 3 | 79 | | | 949 | | | 518 | | | 15 | |
Walter Scott, Jr. Unit No. 4(2) | 60 | | | 225 | | | 134 | | | 8 | |
George Neal Unit No. 4 | 41 | | | 318 | | | 184 | | | 4 | |
Ottumwa Unit No. 1 | 52 | | | 674 | | | 264 | | | 11 | |
George Neal Unit No. 3 | 72 | | | 528 | | | 286 | | | 9 | |
Transmission facilities | Various | | 263 | | | 100 | | | 4 | |
Total | | | $ | 4,553 | | | $ | 2,439 | | | $ | 80 | |
(1)Includes amounts related to nuclear fuel.
(2)Plant in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa regulatory arrangements totaling $561 million and $127 million, respectively.
(5) Regulatory Matters
|
| | | | | | | | | | | | | | |
| | | | | Accumulated | | Construction |
| Company | | Plant in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Louisa Unit No. 1 | 88 | % | | $ | 822 |
| | $ | 443 |
| | $ | 8 |
|
Quad Cities Unit Nos. 1 & 2(1) | 25 |
| | 723 |
| | 407 |
| | 10 |
|
Walter Scott, Jr. Unit No. 3 | 79 |
| | 641 |
| | 304 |
| | 2 |
|
Walter Scott, Jr. Unit No. 4(2) | 60 |
| | 454 |
| | 167 |
| | 1 |
|
George Neal Unit No. 4 | 41 |
| | 310 |
| | 164 |
| | 2 |
|
Ottumwa Unit No. 1 | 52 |
| | 630 |
| | 209 |
| | 6 |
|
George Neal Unit No. 3 | 72 |
| | 442 |
| | 196 |
| | 3 |
|
Transmission facilities | Various |
| | 257 |
| | 92 |
| | — |
|
Total | | | $ | 4,279 |
| | $ | 1,982 |
| | $ | 32 |
|
| |
(1) | Includes amounts related to nuclear fuel. |
| |
(2) | Plant in service and accumulated depreciation and amortization amounts are net of credits applied under Iowa revenue sharing arrangements totaling $319 million and $88 million, respectively. |
Regulatory assets represent costs that are expected to be recovered in future regulated rates. MidAmerican Energy's regulatory assets reflected on the Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
| | | | | |
Asset retirement obligations(1) | 6 years | | $ | 393 | | | $ | 298 | |
Employee benefit plans(2) | 13 years | | 42 | | | 66 | |
Unrealized loss on regulated derivative contracts | 1 year | | 5 | | | — | |
Other | Various | | 33 | | | 28 | |
Total | | | $ | 473 | | | $ | 392 | |
|
| | | | | | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Asset retirement obligations(1) | 12 years | | $ | 160 |
| | $ | 133 |
|
Employee benefit plans(2) | 14 years | | 62 |
| | 38 |
|
Unrealized loss on regulated derivative contracts | 1 year | | 19 |
| | 6 |
|
Other | Various | | 32 |
| | 27 |
|
Total | | | $ | 273 |
| | $ | 204 |
|
(1)Amount predominantly relates to AROs for fossil-fueled and wind-powered generating facilities. Refer to Note 11 for a discussion of AROs. | |
(1) | Amount predominantly relates to asset retirement obligations for fossil-fueled and wind-powered generating facilities. Refer to Note 11 for a discussion of asset retirement obligations. |
| |
(2) | Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized. |
(2)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
MidAmerican Energy had regulatory assets not earning a return on investment of $269$470 million and $200$389 million as of December 31, 20182021 and 2017,2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts expected to be returned to customers in future periods. MidAmerican Energy's regulatory liabilities reflected on the Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Cost of removal accrual(1) | 29 years | | $ | 394 | | | $ | 466 | |
Asset retirement obligations(2) | 31 years | | 341 | | | 300 | |
Iowa electric revenue sharing accrual(3) | 1 year | | 115 | | | — | |
Deferred income taxes(4) | Various | | 83 | | | 263 | |
Employee benefit plans(5) | 9 years | | 55 | | | 20 | |
Pre-funded AFUDC on transmission MVPs(6) | 51 years | | 34 | | | 35 | |
Unrealized gain on regulated derivative contracts | 1 year | | 26 | | | 2 | |
Other | Various | | 32 | | | 25 | |
Total | | | $ | 1,080 | | | $ | 1,111 | |
(1)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing utility plant in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amount represents the excess of nuclear decommission trust assets over the related ARO. Refer to Note 11 for a discussion of AROs.
(3)Represents current-year accruals under a regulatory arrangement in Iowa in which equity returns exceeding specified thresholds reduce utility plant upon final determination.
(4)Amounts primarily represent income tax liabilities primarily related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(5)Represents amounts not yet recognized as a component of net periodic benefit cost that are to be returned to customers in future periods when recognized.
(6)Represents AFUDC accrued on transmission MVPs that is deducted from rate base as a result of the inclusion of related construction work-in-progress in rate base.
Natural Gas Purchased for Resale
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.
To mitigate the impact to MidAmerican Energy's customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. The unbilled portion of these costs as of December 31, 2021, is reflected in trade receivables, net on the Balance Sheet. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the year ended December 31, 2021.
|
| | | | | | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Cost of removal accrual(1) | 29 years | | $ | 708 |
| | $ | 688 |
|
Deferred income taxes(2) | 29 years | | 626 |
| | 681 |
|
Asset retirement obligations(3) | 34 years | | 160 |
| | 173 |
|
Employee benefit plans(4) | N/A | | — |
| | 41 |
|
Pre-funded AFUDC on transmission MVPs(5) | 54 years | | 36 |
| | 35 |
|
Iowa electric revenue sharing accrual(6) | 1 year | | 70 |
| | 26 |
|
Other | Various | | 20 |
| | 17 |
|
Total | | | $ | 1,620 |
| | $ | 1,661 |
|
| |
(1) | Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing utility plant in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost. |
| |
(2) | Amounts primarily represent income tax liabilities primarily related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. See Note 9 for further discussion of 2017 Tax Reform impacts.
|
| |
(3) | Amount predominantly represents the excess of nuclear decommission trust assets over the related asset retirement obligation. Refer to Note 11 for a discussion of asset retirement obligations. |
| |
(4) | Represents amounts not yet recognized as a component of net periodic benefit cost that are to be returned to customers in future periods when recognized. |
| |
(5) | Represents AFUDC accrued on transmission MVPs that is deducted from rate base as a result of the inclusion of related construction work-in-progress in rate base. |
| |
(6) | Represents current-year accruals under a regulatory arrangement in Iowa in which equity returns exceeding specified thresholds reduce utility plant upon final determination. |
(6)Investments and Restricted Investments | |
(6) | Investments and Restricted Investments |
Investments and restricted investments consists of the following amounts as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Nuclear decommissioning trust | $ | 768 | | | $ | 676 | |
Rabbi trusts | 233 | | | 211 | |
Other | 25 | | | 24 | |
Total | $ | 1,026 | | | $ | 911 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Nuclear decommissioning trust | $ | 504 |
| | $ | 515 |
|
Rabbi trusts | 191 |
| | 198 |
|
Other | 13 |
| | 15 |
|
Total | $ | 708 |
| | $ | 728 |
|
MidAmerican Energy has established a trust for the investment of funds for decommissioning the Quad Cities Station. The debt and equity securities in the trust are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station, which is currently licensed for operation until December 2032. As of December 31, 20182021 and 2017,2020, the fair value of the trust's funds was invested as follows: 51%56% and 56%, respectively, in domestic common equity securities, 37%30% and 34%30%, respectively, in United States government securities, 9%12% and 7%11%, respectively, in domestic corporate debt securities and 3%2% and 3%, respectively, in other securities.
Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value. Changes in the cash surrender value of the policies are reflected in other income (expense) - other, net on the Statements of Operation.
(7)Short-TermShort-term Debt and Credit Facilities
Interim financing of working capital needs and the construction program is obtained from unaffiliated parties through the sale of commercial paper or short-term borrowing from banks. The following table summarizes MidAmerican Energy's availability under its unsecured revolving credit facilities as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Credit facilities | $ | 1,505 | | | $ | 1,505 | |
Less: | | | |
| | | |
Variable-rate tax-exempt bond support | (370) | | | (370) | |
Net credit facilities | $ | 1,135 | | | $ | 1,135 | |
As of December 31, 2021, MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2024. In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring June 2021 with a one-year2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and increased the available maturity extension optionoptions to an unlimited number, subject to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. In addition,Additionally, MidAmerican Energy has a $5 million unsecured credit facility, which expires in June 20192022 and has a variable interest rate based on the Eurodollar rate plus a spread.
As of December 31, 2018,2020, in addition to the $900 million unsecured credit facility discussed above, MidAmerican Energy had a $400$600 million unsecured credit facility expiring November 2019,August 2021, which was terminated in January 2019. As of December 31, 2018, the weighted average interest rate onJune 2021. MidAmerican Energy had no commercial paper borrowings outstanding was 2.49%.of as of December 31, 2021 and 2020. The $900 million$1.5 billion credit facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter.
As of December 31, 2018,2021, MidAmerican Energy was in compliance with the covenants of its credit facilities. MidAmerican Energy has authority from the FERC to issue commercial paper and bank notes aggregating $1.3$1.5 billion through July 31, 2020.April 2, 2022.
The following table summarizes MidAmerican Energy's availability under its two unsecured revolving credit facilities as of December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Credit facilities | $ | 1,305 |
| | $ | 905 |
|
Less: | | | |
Short-term debt outstanding | (240 | ) | | — |
|
Variable-rate tax-exempt bond support | (370 | ) | | (370 | ) |
Net credit facilities | $ | 695 |
| | $ | 535 |
|
(8)Long-term Debt
MidAmerican Energy's long-term debt consists of the following, including amounts maturing within one year and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
| | | | | |
First mortgage bonds: | | | | | |
3.70%, due 2023 | $ | 250 | | | $ | 250 | | | $ | 249 | |
3.50%, due 2024 | 500 | | | 501 | | | 501 | |
3.10%, due 2027 | 375 | | | 373 | | | 373 | |
3.65%, due 2029 | 850 | | | 860 | | | 862 | |
4.80%, due 2043 | 350 | | | 346 | | | 346 | |
4.40%, due 2044 | 400 | | | 395 | | | 395 | |
4.25%, due 2046 | 450 | | | 446 | | | 445 | |
3.95%, due 2047 | 475 | | | 470 | | | 470 | |
3.65%, due 2048 | 700 | | | 689 | | | 689 | |
4.25%, due 2049 | 900 | | | 874 | | | 873 | |
3.15%, due 2050 | 600 | | | 592 | | | 592 | |
2.70%, due 2052 | 500 | | | 492 | | | — | |
Notes: | | | | | |
6.75% Series, due 2031 | 400 | | | 397 | | | 397 | |
5.75% Series, due 2035 | 300 | | | 298 | | | 298 | |
5.80% Series, due 2036 | 350 | | | 348 | | | 348 | |
Transmission upgrade obligations, 3.35% to 7.95%, due 2036 to 2041 | 38 | | | 22 | | | 4 | |
Variable-rate tax-exempt bond obligation series: (weighted average interest rate- 2021-0.13%, 2020-0.14%): | | | | | |
Due 2023, issued in 1993 | 7 | | | 7 | | | 7 | |
Due 2023, issued in 2008 | 57 | | | 57 | | | 57 | |
Due 2024 | 35 | | | 35 | | | 35 | |
Due 2025 | 13 | | | 13 | | | 13 | |
Due 2036 | 33 | | | 33 | | | 33 | |
Due 2038 | 45 | | | 45 | | | 45 | |
Due 2046 | 30 | | | 29 | | | 29 | |
Due 2047 | 150 | | | 149 | | | 149 | |
Total | $ | 7,808 | | | $ | 7,721 | | | $ | 7,210 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
| | | | | |
First mortgage bonds: | | | | | |
2.40%, due 2019 | $ | 500 |
| | $ | 500 |
| | $ | 499 |
|
3.70%, due 2023 | 250 |
| | 249 |
| | 248 |
|
3.50%, due 2024 | 500 |
| | 500 |
| | 501 |
|
3.10%, due 2027 | 375 |
| | 372 |
| | 372 |
|
4.80%, due 2043 | 350 |
| | 346 |
| | 346 |
|
4.40%, due 2044 | 400 |
| | 395 |
| | 394 |
|
4.25%, due 2046 | 450 |
| | 445 |
| | 445 |
|
3.95%, due 2047 | 475 |
| | 470 |
| | 470 |
|
3.65%, due 2048 | 700 |
| | 688 |
| | — |
|
Notes: | | | | | |
5.3% Series, due 2018 | — |
| | — |
| | 350 |
|
6.75% Series, due 2031 | 400 |
| | 396 |
| | 396 |
|
5.75% Series, due 2035 | 300 |
| | 298 |
| | 298 |
|
5.8% Series, due 2036 | 350 |
| | 347 |
| | 347 |
|
Transmission upgrade obligation, 4.45% and 3.42% due through 2035 and 2036, respectively | 6 |
| | 5 |
| | 6 |
|
Variable-rate tax-exempt bond obligation series: (weighted average interest rate- 2018-1.74%, 2017-1.91%): | | | | | |
Due 2023, issued in 1993 | 7 |
| | 7 |
| | 7 |
|
Due 2023, issued in 2008 | 57 |
| | 57 |
| | 57 |
|
Due 2024 | 35 |
| | 35 |
| | 35 |
|
Due 2025 | 13 |
| | 13 |
| | 13 |
|
Due 2036 | 33 |
| | 33 |
| | 33 |
|
Due 2038 | 45 |
| | 45 |
| | 45 |
|
Due 2046 | 30 |
| | 29 |
| | 29 |
|
Due 2047 | 150 |
| | 149 |
| | 149 |
|
Capital lease obligations - 4.16%, due through 2020 | 2 |
| | 2 |
| | 2 |
|
Total | $ | 5,428 |
| | $ | 5,381 |
| | $ | 5,042 |
|
The annual repayments of MidAmerican Energy's long-term debt for the years beginning January 1, 2019,2022, and thereafter, excluding unamortized premiums, discounts and debt issuance costs, are as follows (in millions):
| | | | | | | | |
2022 | | $ | — | |
2023 | | 316 | |
2024 | | 537 | |
2025 | | 15 | |
2026 | | 2 | |
2027 and thereafter | | 6,938 | |
|
| | | | |
2019 | | $ | 500 |
|
2020 | | 2 |
|
2021 | | — |
|
2022 | | — |
|
2023 | | 315 |
|
2024 and thereafter | | 4,611 |
|
In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest.
Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, MidAmerican Energy's first mortgage bonds, currently and from time to time outstanding, are secured by a first mortgage lien on substantially all of its electric generating, transmission and distribution property within the Statestate of Iowa, subject to certain exceptions and permitted encumbrances. AsApproximately $22 billion of December 31, 2018, MidAmerican Energy's eligible property, based on original cost, was subject to the lien of the mortgage totaled approximately $18 billion based on original cost.as of December 31, 2021. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.
MidAmerican Energy's variable-rate tax-exempt bond obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy, at its option, may change the mode of interest calculation for these bonds by selecting from among several floating or fixed rate alternatives. The interest rates shown in the table above are the weighted average interest rates as of December 31, 20182021 and 2017.2020. MidAmerican Energy maintains revolving credit facility agreements to provide liquidity for holders of these issues. Additionally, MidAmerican Energy's obligations associated with the $30 million and $150 million variable rate, tax-exempt bond obligations due 2046 and 2047, respectively, are secured by an equal amount of first mortgage bonds pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as supplemented and amended. Proceeds of the $150 million of variable-rate, tax-exempt Solid Waste Facilities Revenue Bonds due December 2047 are restricted for the purpose of constructing solid waste facilities. As of December 31, 2018, $56 million of the restricted proceeds remain and are reflected in other current assets on the Balance Sheet.
As of December 31, 2018,2021, MidAmerican Energy was in compliance with all of its applicable long-term debt covenants.
In March 1999, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval from the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. As of December 31, 2018,2021, MidAmerican Energy's common equity ratio was 53% computed on a basis consistent with its commitment. As a result of its regulatory commitment to maintain its common equity level above certain thresholds, MidAmerican Energy could dividend $2.5$3.3 billion as of December 31, 2018,2021, without falling below 42%.
Tax Cuts and Jobs Act(9)Income Taxes
The 2017 Tax Reform impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018 and limitations on bonus depreciation for utility property. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, MidAmerican Energy reduced deferred income tax liabilities $1,824 million. As it is probable the change in deferred taxes will be passed back to customers through regulatory mechanisms, MidAmerican Energy increased net regulatory liabilities by $1,845 million.
In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. On December 31, 2017, MidAmerican Energy recorded the impacts of 2017 Tax Reform and believed all the impacts to be complete with the exception of interpretations of the bonus depreciation rules. MidAmerican Energy determined the amounts recorded and the interpretations relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. MidAmerican Energy believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, MidAmerican Energy recorded a current tax benefit of $27 million and a deferred tax expense of $28 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform, MidAmerican Energy reduced the associated deferred income tax liabilities $12 million and increased regulatory liabilities by the same amount.
MidAmerican Energy's income tax benefit from continuing operations consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Current: | | | | | |
Federal | $ | (736) | | | $ | (684) | | | $ | (478) | |
State | (92) | | | (94) | | | (47) | |
| (828) | | | (778) | | | (525) | |
Deferred: | | | | | |
Federal | 189 | | | 201 | | | 166 | |
State | (35) | | | 8 | | | (11) | |
| 154 | | | 209 | | | 155 | |
| | | | | |
Investment tax credits | (1) | | | (1) | | | (1) | |
Total | $ | (675) | | | $ | (570) | | | $ | (371) | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Current: | | | | | |
Federal | $ | (276 | ) | | $ | (490 | ) | | $ | (479 | ) |
State | (12 | ) | | (25 | ) | | (14 | ) |
| (288 | ) | | (515 | ) | | (493 | ) |
Deferred: | | | | | |
Federal | 42 |
| | 335 |
| | 366 |
|
State | (8 | ) | | (2 | ) | | (4 | ) |
| 34 |
| | 333 |
| | 362 |
|
| | | | | |
Investment tax credits | (1 | ) | | (1 | ) | | (1 | ) |
Total | $ | (255 | ) | | $ | (183 | ) | | $ | (132 | ) |
Iowa Senate File 2417
In May 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% and eliminates corporate federal deductibility, both for tax years starting in 2021. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of Iowa Senate File 2417, MidAmerican Energy reduced net deferred income tax liabilities $54 million and decreased deferred income tax benefit by $2 million. As it is probable the change in deferred taxes for MidAmerican Energy will be passed back to customers through regulatory mechanisms, MidAmerican Energy increased net regulatory liabilities by $56 million.
A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (262) | | | (199) | | | (90) | |
State income tax, net of federal income tax benefit | (46) | | | (27) | | | (11) | |
Effects of ratemaking | (20) | | | (17) | | | (8) | |
Other, net | (1) | | | (1) | | | — | |
Effective income tax rate | (308) | % | | (223) | % | | (88) | % |
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
Income tax credits | (73 | ) | | (68 | ) | | (61 | ) |
State income tax, net of federal income tax benefit | (4 | ) | | (4 | ) | | (3 | ) |
Effects of ratemaking | (5 | ) | | (7 | ) | | (3 | ) |
2017 Tax Reform | 1 |
| | 2 |
| | — |
|
Other, net | — |
| | (1 | ) | | — |
|
Effective income tax rate | (60 | )% | | (43 | )% | | (32 | )% |
Income tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity production tax creditsPTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
MidAmerican Energy's net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 240 | | | $ | 288 | |
| | | |
Asset retirement obligations | 220 | | | 229 | |
State carryforwards | 55 | | | 52 | |
Employee benefits | 26 | | | 42 | |
Other | 30 | | | 40 | |
Total deferred income tax assets | 571 | | | 651 | |
Valuation allowances | (1) | | | (25) | |
Total deferred income tax assets, net | 570 | | | 626 | |
| | | |
Deferred income tax liabilities: | | | |
Depreciable property | (3,843) | | | (3,583) | |
Regulatory assets | (112) | | | (97) | |
Other | (4) | | | — | |
Total deferred income tax liabilities | (3,959) | | | (3,680) | |
| | | |
Net deferred income tax liability | $ | (3,389) | | | $ | (3,054) | |
|
| | | | | | | |
| 2018 | | 2017 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 405 |
| | $ | 443 |
|
Asset retirement obligations | 164 |
| | 160 |
|
Employee benefits | 47 |
| | 45 |
|
Other | 80 |
| | 57 |
|
Total deferred income tax assets | 696 |
| | 705 |
|
| | | |
Deferred income tax liabilities: | | | |
Depreciable property | (2,945 | ) | | (2,865 | ) |
Regulatory assets | (61 | ) | | (42 | ) |
Other | (12 | ) | | (35 | ) |
Total deferred income tax liabilities | (3,018 | ) | | (2,942 | ) |
| | | |
Net deferred income tax liability | $ | (2,322 | ) | | $ | (2,237 | ) |
As of December 31, 2018,2021, MidAmerican Energy has available $44 million ofEnergy's state tax carryforwards, principally related to $655$823 million of net operating losses, that expire at various intervals between 20192022 and 2037.2040.
The United States Internal Revenue Service has closed or effectively settled its examination of MidAmerican Energy's income tax returns through December 31, 2011.2013. The statute of limitations for MidAmerican Energy's state income tax returns have expired through December 31, 2009, with the exception of Iowa2011, for Michigan and Illinois, for which the statute of limitations have expiredNebraska, and through December 31, 2014,2017, for Illinois, Indiana, Iowa, Kansas and Missouri, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
A reconciliation of the beginning and ending balances of MidAmerican Energy's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 8 | | | $ | 8 | |
Additions based on tax positions related to the current year | 16 | | | 4 | |
| | | |
Reductions based on tax positions related to the current year | (11) | | | (3) | |
Reductions for tax positions of prior years | — | | | (1) | |
| | | |
| | | |
| | | |
Ending balance | $ | 13 | | | $ | 8 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 12 |
| | $ | 10 |
|
Additions based on tax positions related to the current year | 4 |
| | 1 |
|
Additions for tax positions of prior years | 47 |
| | 23 |
|
Reductions based on tax positions related to the current year | (4 | ) | | (4 | ) |
Reductions for tax positions of prior years | (48 | ) | | (19 | ) |
Interest and penalties | (1 | ) | | 1 |
|
Ending balance | $ | 10 |
| | $ | 12 |
|
As of December 31, 2018,2021, MidAmerican Energy had unrecognized tax benefits totaling $29$33 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MidAmerican Energy's effective income tax rate.
286
| |
(10) | Employee Benefit Plans |
(10)Employee Benefit Plans
Defined Benefit Plan
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. Benefit obligations under the plan are based on a cash balance arrangement for salaried employees and most union employees and final average pay formulas for other union employees. MidAmerican Energy also maintains noncontributory, nonqualified defined benefit supplemental executive retirement plans ("SERP") for certain active and retired participants. In 2018,2021, the defined benefit pension plan recorded a settlement gain of $1$5 million for previously unrecognized gains as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018.2021.
MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. Under the plans, a majority of all employees of the participating companies may become eligible for these benefits if they reach retirement age. New employees are not eligible for benefits under the plans. MidAmerican Energy has been allowed to recover accrued pension and other postretirement benefit costs in its electric and gas service rates.
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. and Dominion Energy Questar Corporation, exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "GT&S Transaction"). Defined benefit pension and postretirement benefits provided to the employees of GT&S are administered in the respective plans sponsored by MidAmerican Energy. Initial pension and postretirement plan liabilities of $81 million and $37 million, respectively, resulted from the GT&S Transaction and are included in plan obligations and affiliate receivables on MidAmerican Energy's Balance Sheet.
Net Periodic Benefit Cost
For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns on equity investments over a five-year period beginning after the first year in which they occur.
MidAmerican Energy bills to and is reimbursed currently for affiliates' share of the net periodic benefit costs from all plans in which such affiliates participate. In 2018, 20172021, 2020 and 2016,2019, MidAmerican Energy's share of the pension net periodic benefit (credit) cost was $(9)$(20) million, $(6)$(13) million and $(2)$(8) million, respectively. MidAmerican Energy's share of the other postretirement net periodic benefit (credit) cost in 2018, 20172021, 2020 and 20162019 totaled $(2)$1 million, $(1)$(5) million and $(1)$1 million, respectively.
Net periodic benefit cost for the plans of MidAmerican Energy and the aforementioned affiliates included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
Service cost | $ | 20 | | | $ | 8 | | | $ | 6 | | | $ | 9 | | | $ | 4 | | | $ | 5 | |
Interest cost | 22 | | | 25 | | | 30 | | | 8 | | | 7 | | | 10 | |
Expected return on plan assets | (37) | | | (40) | | | (41) | | | (10) | | | (14) | | | (13) | |
Settlement | (5) | | | — | | | — | | | — | | | — | | | — | |
Net amortization | 1 | | | 1 | | | 1 | | | (4) | | | (5) | | | (3) | |
Net periodic benefit cost (credit) | $ | 1 | | | $ | (6) | | | $ | (4) | | | $ | 3 | | | $ | (8) | | | $ | (1) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | |
Service cost | $ | 9 |
| | $ | 9 |
| | $ | 10 |
| | $ | 5 |
| | $ | 5 |
| | $ | 5 |
|
Interest cost | 28 |
| | 31 |
| | 34 |
| | 8 |
| | 9 |
| | 10 |
|
Expected return on plan assets | (44 | ) | | (44 | ) | | (44 | ) | | (13 | ) | | (14 | ) | | (13 | ) |
Settlement | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Net amortization | 2 |
| | 2 |
| | 2 |
| | (4 | ) | | (4 | ) | | (4 | ) |
Net periodic benefit (credit) cost | $ | (6 | ) | | $ | (2 | ) | | $ | 2 |
| | $ | (4 | ) | | $ | (4 | ) | | $ | (2 | ) |
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 718 | | | $ | 717 | | | $ | 278 | | | $ | 272 | |
Employer contributions | 8 | | | 6 | | | 10 | | | 3 | |
Participant contributions | — | | | — | | | 1 | | | 1 | |
Actual return on plan assets | 58 | | | 55 | | | 34 | | | 15 | |
Settlement | (46) | | | — | | | — | | | — | |
Benefits paid | (34) | | | (60) | | | (15) | | | (13) | |
Plan assets at fair value, end of year | $ | 704 | | | $ | 718 | | | $ | 308 | | | $ | 278 | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Plan assets at fair value, beginning of year | $ | 745 |
| | $ | 684 |
| | $ | 277 |
| | $ | 252 |
|
Employer contributions | 7 |
| | 7 |
| | 1 |
| | 1 |
|
Participant contributions | — |
| | — |
| | 1 |
| | 1 |
|
Actual return on plan assets | (39 | ) | | 114 |
| | (17 | ) | | 36 |
|
Settlement | (37 | ) | | — |
| | — |
| | — |
|
Benefits paid | (32 | ) | | (60 | ) | | (15 | ) | | (13 | ) |
Plan assets at fair value, end of year | $ | 644 |
| | $ | 745 |
| | $ | 247 |
| | $ | 277 |
|
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 845 | | | $ | 763 | | | $ | 304 | | | $ | 226 | |
Service cost | 20 | | | 8 | | | 9 | | | 4 | |
Interest cost | 22 | | | 25 | | | 8 | | | 7 | |
Participant contributions | — | | | — | | | 1 | | | 1 | |
Actuarial (gain) loss | (25) | | | 28 | | | (18) | | | 42 | |
Plan amendments | — | | | — | | | 1 | | | — | |
Settlement | (46) | | | — | | | — | | | — | |
Acquisition | (1) | | | 81 | | | (5) | | | 37 | |
Benefits paid | (34) | | | (60) | | | (15) | | | (13) | |
Benefit obligation, end of year | $ | 781 | | | $ | 845 | | | $ | 285 | | | $ | 304 | |
Accumulated benefit obligation, end of year | $ | 721 | | | $ | 773 | | | | | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Benefit obligation, beginning of year | $ | 799 |
| | $ | 773 |
| | $ | 246 |
| | $ | 233 |
|
Service cost | 9 |
| | 9 |
| | 5 |
| | 5 |
|
Interest cost | 28 |
| | 31 |
| | 8 |
| | 9 |
|
Participant contributions | — |
| | — |
| | 1 |
| | 1 |
|
Actuarial (gain) loss | (33 | ) | | 46 |
| | (3 | ) | | 11 |
|
Plan amendments | 2 |
| | — |
| | — |
| | — |
|
Settlement | (37 | ) | | — |
| | — |
| | — |
|
Benefits paid | (32 | ) | | (60 | ) | | (15 | ) | | (13 | ) |
Benefit obligation, end of year | $ | 736 |
| | $ | 799 |
| | $ | 242 |
| | $ | 246 |
|
Accumulated benefit obligation, end of year | $ | 733 |
| | $ | 790 |
| | | | |
The funded status of the plans and the amounts recognized on the Balance Sheets as of December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 704 | | | $ | 718 | | | $ | 308 | | | $ | 278 | |
Less - Benefit obligation, end of year | 781 | | | 845 | | | 285 | | | 304 | |
Funded status | $ | (77) | | | $ | (127) | | | $ | 23 | | | $ | (26) | |
| | | | | | | |
Amounts recognized on the Balance Sheets: | | | | | | | |
Other assets | $ | 34 | | | $ | — | | | $ | 23 | | | $ | — | |
Other current liabilities | (7) | | | (7) | | | — | | | — | |
Other liabilities | (104) | | | (120) | | | — | | | (26) | |
Amounts recognized | $ | (77) | | | $ | (127) | | | $ | 23 | | | $ | (26) | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Plan assets at fair value, end of year | $ | 644 |
| | $ | 745 |
| | $ | 247 |
| | $ | 277 |
|
Less - Benefit obligation, end of year | 736 |
| | 799 |
| | 242 |
| | 246 |
|
Funded status | $ | (92 | ) | | $ | (54 | ) | | $ | 5 |
| | $ | 31 |
|
| | | | | | | |
Amounts recognized on the Balance Sheets: | | | | | | | |
Other assets | $ | 17 |
| | $ | 66 |
| | $ | 5 |
| | $ | 31 |
|
Other current liabilities | (7 | ) | | (8 | ) | | — |
| | — |
|
Other liabilities | (102 | ) | | (112 | ) | | — |
| | — |
|
Amounts recognized | $ | (92 | ) | | $ | (54 | ) | | $ | 5 |
| | $ | 31 |
|
The SERP has no plan assets; however, MidAmerican Energy and BHE have Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in MidAmerican Energy's Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $116$143 million and $118$130 million as of December 31, 20182021 and 2017.2020. These assets are not included in the plan assets in the above table, but are reflected in investments and restricted investments on the Balance Sheets. The accumulated benefit obligation and projected benefit obligation for the SERP was $109$111 million and $109$111 million for 20182021 and $118$117 million and $120$117 million for 2017,2020, respectively.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net (gain) loss | $ | (25) | | | $ | 18 | | | $ | 2 | | | $ | 45 | |
Prior service (credit) cost | — | | | — | | | (3) | | | (9) | |
| | | | | | | |
Total | $ | (25) | | | $ | 18 | | | $ | (1) | | | $ | 36 | |
|
| | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2018 | | 2017 |
| | | | | | | |
Net loss (gain) | $ | 40 |
| | $ | (11 | ) | | $ | 48 |
| | $ | 23 |
|
Prior service cost (credit) | 1 |
| | 1 |
| | (20 | ) | | (25 | ) |
Total | $ | 41 |
| | $ | (10 | ) | | $ | 28 |
| | $ | (2 | ) |
MidAmerican Energy sponsors pension and other postretirement benefit plans on behalf of certain of its affiliates in addition to itself, and therefore, the portion of the funded status of the respective plans that has not yet been recognized in net periodic benefit cost is attributable to multiple entities. Additionally, substantially all of MidAmerican Energy's portion of such amounts is either refundable to or recoverable from its customers and is reflected as regulatory liabilities and regulatory assets.
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 20182021 and 20172020 is as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Regulatory Asset | | Regulatory Liability | | Receivables (Payables) with Affiliates | | Total |
Pension | | | | | | | |
Balance, December 31, 2019 | $ | 19 | | | $ | (32) | | | $ | 18 | | | $ | 5 | |
Net (gain) loss arising during the year | 3 | | | 12 | | | (1) | | | 14 | |
| | | | | | | |
Net amortization | (1) | | | — | | | — | | | (1) | |
| | | | | | | |
Total | 2 | | | 12 | | | (1) | | | 13 | |
Balance, December 31, 2020 | 21 | | | (20) | | | 17 | | | 18 | |
Net loss (gain) arising during the year | 2 | | | (40) | | | (9) | | | (47) | |
| | | | | | | |
Net amortization | (1) | | | — | | | — | | | (1) | |
Settlement | — | | | 5 | | | — | | | 5 | |
Total | 1 | | | (35) | | | (9) | | | (43) | |
Balance, December 31, 2021 | $ | 22 | | | $ | (55) | | | $ | 8 | | | $ | (25) | |
|
| | | | | | | | | | | | | | | |
| Regulatory Asset | | Regulatory Liability | | Receivables (Payables) with Affiliates | | Total |
Pension | | | | | | | |
Balance, December 31, 2016 | $ | 22 |
| | $ | (12 | ) | | $ | 6 |
| | $ | 16 |
|
Net loss (gain) arising during the year | 4 |
| | (29 | ) | | 1 |
| | (24 | ) |
Net amortization | (2 | ) | | — |
| | — |
| | (2 | ) |
Total | 2 |
| | (29 | ) | | 1 |
| | (26 | ) |
Balance, December 31, 2017 | 24 |
| | (41 | ) | | 7 |
| | (10 | ) |
Net loss arising during the year | 2 |
| | 41 |
| | 9 |
| | 52 |
|
Net amortization | (2 | ) | | — |
| | — |
| | (2 | ) |
Settlement | 1 |
| | — |
| | — |
| | 1 |
|
Total | 1 |
| | 41 |
| | 9 |
| | 51 |
|
Balance, December 31, 2018 | $ | 25 |
| | $ | — |
| | $ | 16 |
| | $ | 41 |
|
| | | | | | | | | | | | | | | | | | | |
| Regulatory Asset | | | | Receivables (Payables) with Affiliates | | Total |
Other Postretirement | | | | | | | |
Balance, December 31, 2019 | $ | 7 | | | | | $ | (17) | | | $ | (10) | |
Net gain arising during the year | 34 | | | | | 7 | | | 41 | |
| | | | | | | |
Net amortization | 4 | | | | | 1 | | | 5 | |
Total | 38 | | | | | 8 | | | 46 | |
Balance, December 31, 2020 | 45 | | | | | (9) | | | 36 | |
Net loss arising during the year | (29) | | | | | (13) | | | (42) | |
Net prior service cost arising during the year | 1 | | | | | — | | | 1 | |
Net amortization | 3 | | | | | 1 | | | 4 | |
Total | (25) | | | | | (12) | | | (37) | |
Balance, December 31, 2021 | $ | 20 | | | | | $ | (21) | | | $ | (1) | |
|
| | | | | | | | | | | |
| Regulatory Asset | | Receivables (Payables) with Affiliates | | Total |
Other Postretirement | | | | | |
Balance, December 31, 2016 | $ | 18 |
| | $ | (13 | ) | | $ | 5 |
|
Net gain arising during the year | (7 | ) | | (4 | ) | | (11 | ) |
Net amortization | 3 |
| | 1 |
| | 4 |
|
Total | (4 | ) | | (3 | ) | | (7 | ) |
Balance, December 31, 2017 | 14 |
| | (16 | ) | | (2 | ) |
Net loss arising during the year | 20 |
| | 6 |
| | 26 |
|
Net amortization | 3 |
| | 1 |
| | 4 |
|
Total | 23 |
| | 7 |
| | 30 |
|
Balance, December 31, 2018 | $ | 37 |
| | $ | (9 | ) | | $ | 28 |
|
Actuarial losses for 2018 impacting the December 31, 2018 funded status for the pension and other postretirement plans are due to lower than assumed actual return on plan assets, offset by an increase in the discount rate assumptions from that assumed at December 31, 2017.
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 3.05 | % | | 2.75 | % | | 3.40 | % | | 2.95 | % | | 2.65 | % | | 3.20 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan | | | | | | | | | | | |
2019 | N/A | | N/A | | 3.40 | % | | N/A | | N/A | | N/A |
2020 | N/A | | 2.27 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2021 | 1.19 | % | | 0.99 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2022 | 1.19 | % | | 0.99 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2023 | 1.19 | % | | 0.99 | % | | 2.27 | % | | N/A | | N/A | | N/A |
2024 and beyond | 1.19 | % | | 0.99 | % | | 2.27 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | | |
Discount rate | 2.75 | % | | 3.40 | % | | 4.25 | % | | 2.65 | % | | 3.20 | % | | 4.15 | % |
Expected return on plan assets(1) | 5.60 | % | | 6.25 | % | | 6.50 | % | | 4.00 | % | | 6.00 | % | | 6.25 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A | | N/A | | N/A |
Interest crediting rates for cash balance plan | 1.19 | % | | 2.27 | % | | 3.40 | % | | N/A | | N/A | | N/A |
|
| | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
Benefit obligations as of December 31: | | | | | | | | | | | |
Discount rate | 4.25 | % | | 3.60 | % | | 4.10 | % | | 4.15 | % | | 3.50 | % | | 3.90 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A |
| | N/A |
| | N/A |
|
Interest crediting rates for cash balance plan | | | | | | | | | | | |
2016 | N/A |
| | N/A |
| | 1.18 | % | | N/A |
| | N/A |
| | N/A |
|
2017 | N/A |
| | 1.44 | % | | 1.44 | % | | N/A |
| | N/A |
| | N/A |
|
2018 | 2.26 | % | | 2.26 | % | | 1.44 | % | | N/A |
| | N/A |
| | N/A |
|
2019 | 3.40 | % | | 2.26 | % | | 2.10 | % | | N/A |
| | N/A |
| | N/A |
|
2020 | 3.40 | % | | 1.60 | % | | 2.10 | % | | N/A |
| | N/A |
| | N/A |
|
2021 and beyond | 3.40 | % | | 1.60 | % | | 2.10 | % | | N/A |
| | N/A |
| | N/A |
|
| | | | | | | | | | | |
Net periodic benefit cost for the years ended December 31: | | | | | | | | | | | |
Discount rate | 3.60 | % | | 4.10 | % | | 4.50 | % | | 3.50 | % | | 3.90 | % | | 4.25 | % |
Expected return on plan assets(1) | 6.50 | % | | 6.75 | % | | 7.00 | % | | 6.25 | % | | 6.50 | % | | 6.75 | % |
Rate of compensation increase | 2.75 | % | | 2.75 | % | | 2.75 | % | | N/A |
| | N/A |
| | N/A |
|
Interest crediting rates for cash balance plan | 2.26 | % | | 1.44 | % | | 1.18 | % | | N/A |
| | N/A |
| | N/A |
|
(1)Amounts reflected are pretax values. Assumed after-tax returns for a taxable, non-union other postretirement plan were 2.39% for 2021, 4.62% for 2020 and 4.62% for 2019. | |
(1) | Amounts reflected are pre-tax values. Assumed after-tax returns for a taxable, non-union other postretirement plan were 4.13% for 2018, and 4.81% for 2017, and 5.00% for 2016. |
In establishing its assumption as to the expected return on plan assets, MidAmerican Energy utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
| | | | | | | | | | | |
| 2021 | | 2020 |
Assumed healthcare cost trend rates as of December 31: | | | |
Healthcare cost trend rate assumed for next year | 5.90 | % | | 6.20 | % |
Rate that the cost trend rate gradually declines to | 5.00 | % | | 5.00 | % |
Year that the rate reaches the rate it is assumed to remain at | 2025 | | 2025 |
|
| | | | | |
| 2018 | | 2017 |
Assumed healthcare cost trend rates as of December 31: | | | |
Healthcare cost trend rate assumed for next year | 6.80 | % | | 7.10 | % |
Rate that the cost trend rate gradually declines to | 5.00 | % | | 5.00 | % |
Year that the rate reaches the rate it is assumed to remain at | 2025 | | 2025 |
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $1$3 million, respectively, during 2019.2022. Funding to MidAmerican Energy's qualified pension benefit plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. MidAmerican Energy considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. MidAmerican Energy's funding policy forEnergy evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan is to generally contribute amounts consistent with its rate regulatory arrangements.plans.
Net periodic benefit costs assigned to MidAmerican Energy affiliates are reimbursed currently in accordance with its intercompany administrative services agreement. The expected benefit payments to participants in MidAmerican Energy's pension and other postretirement benefit plans for 20192022 through 20232026 and for the five years thereafter are summarized below (in millions):
| | | | | | | | | | | |
| Projected Benefit Payments |
| Pension | | Other Postretirement |
| | | |
2022 | $ | 56 | | | $ | 21 | |
2023 | 55 | | | 22 | |
2024 | 54 | | | 22 | |
2025 | 52 | | | 22 | |
2026 | 51 | | | 22 | |
2027-2031 | 229 | | | 98 | |
|
| | | | | | | |
| Projected Benefit Payments |
| Pension | | Other Postretirement |
| | | |
2019 | $ | 61 |
| | $ | 19 |
|
2020 | 62 |
| | 21 |
|
2021 | 61 |
| | 22 |
|
2022 | 60 |
| | 22 |
|
2023 | 58 |
| | 22 |
|
2024-2028 | 262 |
| | 102 |
|
Plan Assets
Investment Policy and Asset Allocations
MidAmerican Energy's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the MidAmericanBerkshire Hathaway Energy Pension and Employee Benefits Plans AdministrativeCompany Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
The target allocations (percentage of plan assets) for MidAmerican Energy's pension and other postretirement benefit plan assets are as follows as of December 31, 2018:
| | | | | | | | | | | |
| Pension | | Other Postretirement |
| % | | % |
Debt securities(1) | 60-80 | | 25-35 |
Equity securities(1) | 20-40 | | 65-75 |
| | | |
Other | Pension0-15 | | Other
Postretirement
|
| % | | % |
Debt securities(1)
| 20-50 | | 25-45 |
Equity securities(1)
| 60-80 | | 45-80 |
Real estate funds | 2-8 | | — |
Other | 0-3 | | 0-5 |
| |
(1) | For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities. |
(1)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for MidAmerican Energy's defined benefit pension plan (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | — | | | $ | 27 | | | $ | — | | | $ | 27 | |
Debt securities: | | | | | | | |
United States government obligations | 33 | | | — | | | — | | | 33 | |
International government obligations | — | | | — | | | — | | | — | |
Corporate obligations | — | | | 242 | | | — | | | 242 | |
Municipal obligations | — | | | 18 | | | — | | | 18 | |
Agency, asset and mortgage-backed obligations | — | | | 17 | | | — | | | 17 | |
Equity securities: | | | | | | | |
United States companies | 35 | | | — | | | — | | | 35 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total assets in the hierarchy | $ | 68 | | | $ | 304 | | | $ | — | | | 372 | |
Investment funds(2) measured at net asset value | | | | | | | 332 | |
| | | | | | | |
| | | | | | | |
Total assets measured at fair value | | | | | | | $ | 704 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | — | | | $ | 26 | | | $ | — | | | $ | 26 | |
Debt securities: | | | | | | | |
United States government obligations | 14 | | | — | | | — | | | 14 | |
International government obligations | — | | | — | | | — | | | — | |
Corporate obligations | — | | | 160 | | | — | | | 160 | |
Municipal obligations | — | | | 17 | | | — | | | 17 | |
Agency, asset and mortgage-backed obligations | — | | | — | | | — | | | — | |
Equity securities: | | | | | | | |
United States companies | 65 | | | — | | | — | | | 65 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total assets in the hierarchy | $ | 79 | | | $ | 203 | | | $ | — | | | 282 | |
Investment funds(2) measured at net asset value | | | | | | | 393 | |
| | | | | | | |
Real estate funds measured at net asset value | | | | | | | 43 | |
Total assets measured at fair value | | | | | | | $ | 718 | |
(1)Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 56% and 44%, respectively, for 2021 and 65% and 35%, respectively, for 2020. Additionally, these funds are invested in United States and international securities of approximately 90% and 10%, respectively, for 2021 and 82% and 18%, respectively, for 2020.
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2018: | | | | | | | |
Cash equivalents | $ | — |
| | $ | 20 |
| | $ | — |
| | $ | 20 |
|
Debt securities: | | | | | | | |
United States government obligations | 6 |
| | — |
| | — |
| | 6 |
|
Corporate obligations | — |
| | 63 |
| | — |
| | 63 |
|
Municipal obligations | — |
| | 6 |
| | — |
| | 6 |
|
Agency, asset and mortgage-backed obligations | — |
| | 37 |
| | — |
| | 37 |
|
Equity securities: | | | | | | | |
United States companies | 111 |
| | — |
| | — |
| | 111 |
|
International companies | 35 |
| | — |
| | — |
| | 35 |
|
Investment funds(2) | 65 |
| | — |
| | — |
| | 65 |
|
Total assets in the hierarchy | $ | 217 |
| | $ | 126 |
| | $ | — |
| | — |
|
Investment funds(2) measured at net asset value | | | | | | | 260 |
|
Real estate funds measured at net asset value | | | | | | | 41 |
|
Total assets measured at fair value | | | | | | | $ | 644 |
|
| | | | | | | |
As of December 31, 2017: | | | | | | | |
Cash equivalents | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | 17 |
|
Debt securities: | | | | | | | |
United States government obligations | 21 |
| | — |
| | — |
| | 21 |
|
Corporate obligations | — |
| | 59 |
| | — |
| | 59 |
|
Municipal obligations | — |
| | 7 |
| | — |
| | 7 |
|
Agency, asset and mortgage-backed obligations | — |
| | 33 |
| | — |
| | 33 |
|
Equity securities: | | | | | | | |
United States companies | 137 |
| | — |
| | — |
| | 137 |
|
International companies | 44 |
| | — |
| | — |
| | 44 |
|
Investment funds(2) | 74 |
| | — |
| | — |
| | 74 |
|
Total assets in the hierarchy | $ | 276 |
| | $ | 116 |
| | $ | — |
| | 392 |
|
Investment funds(2) measured at net asset value | | | | | | | 315 |
|
Real estate funds measured at net asset value | | | | | | | 38 |
|
Total assets measured at fair value | | | | | | | $ | 745 |
|
| |
(1) | Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
|
| |
(2) | Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 65% and 35%, respectively, for 2018 and 69% and 31%, respectively, for 2017. Additionally, these funds are invested in United States and international securities of approximately 74% and 26%, respectively, for 2018 and 72% and 28%, respectively, for 2017.
|
The following table presents the fair value of plan assets, by major category, for MidAmerican Energy's defined benefit other postretirement plans (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Cash equivalents | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | |
Debt securities: | | | | | | | |
United States government obligations | 3 | | | — | | | — | | | 3 | |
| | | | | | | |
Corporate obligations | — | | | 6 | | | — | | | 6 | |
Municipal obligations | — | | | 28 | | | — | | | 28 | |
Agency, asset and mortgage-backed obligations | — | | | 3 | | | — | | | 3 | |
Equity securities: | | | | | | | |
| | | | | | | |
| | | | | | | |
Investment funds(2) | 260 | | | — | | | — | | | 260 | |
| | | | | | | |
| | | | | | | |
Total assets measured at fair value | $ | 271 | | | $ | 37 | | | $ | — | | | $ | 308 | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Cash equivalents | $ | 11 | | | $ | — | | | $ | — | | | $ | 11 | |
Debt securities: | | | | | | | |
United States government obligations | 3 | | | — | | | — | | | 3 | |
Corporate obligations | — | | | 7 | | | — | | | 7 | |
Municipal obligations | — | | | 65 | | | — | | | 65 | |
Agency, asset and mortgage-backed obligations | — | | | 3 | | | — | | | 3 | |
Equity securities: | | | | | | | |
| | | | | | | |
Investment funds(2) | 189 | | | — | | | — | | | 189 | |
Total assets measured at fair value | $ | 203 | | | $ | 75 | | | $ | — | | | $ | 278 | |
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements(1) | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2018: | | | | | | | |
Cash equivalents | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
Debt securities: | | | | | | | |
United States government obligations | 6 |
| | — |
| | — |
| | 6 |
|
Corporate obligations | — |
| | 12 |
| | — |
| | 12 |
|
Municipal obligations | — |
| | 43 |
| | — |
| | 43 |
|
Agency, asset and mortgage-backed obligations | — |
| | 12 |
| | — |
| | 12 |
|
Equity securities: | | | | | | | |
United States companies | 73 |
| | — |
| | — |
| | 73 |
|
Investment funds(2) | 96 |
| | — |
| | — |
| | 96 |
|
Total assets measured at fair value | $ | 180 |
| | $ | 67 |
| | $ | — |
| | $ | 247 |
|
| | | | | | | |
As of December 31, 2017: | | | | | | | |
Cash equivalents | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Debt securities: | | | | | | | |
United States government obligations | 5 |
| | — |
| | — |
| | 5 |
|
Corporate obligations | — |
| | 14 |
| | — |
| | 14 |
|
Municipal obligations | — |
| | 44 |
| | — |
| | 44 |
|
Agency, asset and mortgage-backed obligations | — |
| | 12 |
| | — |
| | 12 |
|
Equity securities: | | | | | | | |
United States companies | 84 |
| | — |
| | — |
| | 84 |
|
Investment funds(2) | 112 |
| | — |
| | — |
| | 112 |
|
Total assets measured at fair value | $ | 207 |
| | $ | 70 |
| | $ | — |
| | $ | 277 |
|
(1)Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy. | |
(1) | Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
|
| |
(2) | Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 78% and 22%, respectively, for 2018 and 81% and 19%, respectively, for 2017. Additionally, these funds are invested in United States and international securities of approximately 41% and 59%, respectively, for 2018 and 42% and 58%, respectively, for 2017.
|
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 82% and 18%, respectively, for 2021 and 56% and 44%, respectively, for 2020. Additionally, these funds are invested in United States and international securities of approximately 82% and 18%, respectively, for 2021 and 56% and 44%, respectively, for 2020.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Defined Contribution Plan
MidAmerican Energy sponsors a defined contribution plan ("401(k) plan") covering substantially all employees. MidAmerican Energy's matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pre-taxpretax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. Certain participants now receive enhanced benefits in the 401(k) plan and no longer accrue benefits in the noncontributory defined benefit pension plans. MidAmerican Energy's contributions to the plan were $22$27 million, $20$26 million, and $20$23 million for the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
293
| |
(11) | Asset Retirement Obligations |
(11)Asset Retirement Obligations
MidAmerican Energy estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
MidAmerican Energy does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $708$394 million and $688$466 million as of December 31, 20182021 and 2017,2020, respectively.
The following table presents MidAmerican Energy's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Quad Cities Station | $ | 427 | | | $ | 376 | |
Fossil-fueled generating facilities | 161 | | | 255 | |
Wind-powered generating facilities | 197 | | | 185 | |
Other | 2 | | | 2 | |
Total asset retirement obligations | $ | 787 | | | $ | 818 | |
| | | |
Quad Cities Station nuclear decommissioning trust funds(1) | $ | 768 | | | $ | 676 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Quad Cities Station | $ | 345 |
| | $ | 342 |
|
Fossil-fueled generating facilities | 93 |
| | 113 |
|
Wind-powered generating facilities | 123 |
| | 103 |
|
Other | 1 |
| | 1 |
|
Total asset retirement obligations | $ | 562 |
| | $ | 559 |
|
| | | |
Quad Cities Station nuclear decommissioning trust funds(1) | $ | 504 |
| | $ | 515 |
|
(1)Refer to Note 6 for a discussion of the Quad Cities Station nuclear decommissioning trust funds. | |
(1) | Refer to Note 6 for a discussion of the Quad Cities Station nuclear decommissioning trust funds. |
The following table reconciles the beginning and ending balances of MidAmerican Energy's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 818 | | | $ | 839 | |
Change in estimated costs | 35 | | | 47 | |
Additions | 6 | | | 23 | |
Retirements | (103) | | | (124) | |
Accretion | 31 | | | 33 | |
Ending balance | $ | 787 | | | $ | 818 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 73 | | | $ | 109 | |
Asset retirement obligations | 714 | | | 709 | |
| $ | 787 | | | $ | 818 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 559 |
| | $ | 567 |
|
Change in estimated costs | (10 | ) | | (14 | ) |
Additions | 17 |
| | 8 |
|
Retirements | (28 | ) | | (26 | ) |
Accretion | 24 |
| | 24 |
|
Ending balance | $ | 562 |
| | $ | 559 |
|
| | | |
Reflected as: | | | |
Other current liabilities | $ | 10 |
| | $ | 31 |
|
Asset retirement obligations | 552 |
| | 528 |
|
| $ | 562 |
| | $ | 559 |
|
The changesRetirements in estimated costs2021 and 2020 relate primarily to the Quad Cities Station due to a change in the inflation rate and, for 2017, a new decommissioning study conducted by the operatorsettlements of Quad Cities Station that changed the estimated amount and timing of cash flows.
In January 2018, MidAmerican Energy completed groundwater testing at itsEnergy's coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and will remove all CCR material located below the water table in such facilities, the latter of which is a more extensive closure activity than previously assumed. The incremental cost and timing of such actions is not currently reasonably determinable, but an evaluation of such estimates is expected to be completed in the first quarter of 2019, with any necessary adjustments to the related asset retirement obligations recognized at that time.ARO liabilities.
294
| |
(12) | Fair Value Measurements |
(12)Fair Value Measurements
The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.
The following table presents MidAmerican Energy's financial assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2021: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | 32 | | | $ | 3 | | | $ | (7) | | | $ | 28 | |
| | | | | | | | | | |
| | | | | | | | | | |
Money market mutual funds | | 228 | | | — | | | — | | | — | | | 228 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 232 | | | — | | | — | | | — | | | 232 | |
International government obligations | | — | | | 2 | | | — | | | — | | | 2 | |
Corporate obligations | | — | | | 90 | | | — | | | — | | | 90 | |
Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
Agency, asset and mortgage-backed obligations | | — | | | 2 | | | — | | | — | | | 2 | |
| | | | | | | | | | |
Equity securities: | | | | | | | | | | |
United States companies | | 428 | | | — | | | — | | | — | | | 428 | |
International companies | | 10 | | | — | | | — | | | — | | | 10 | |
Investment funds | | 18 | | | — | | | — | | | — | | | 18 | |
| | $ | 916 | | | $ | 129 | | | $ | 3 | | | $ | (7) | | | $ | 1,041 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | — | | | $ | (6) | | | $ | (8) | | | $ | 12 | | | $ | (2) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
As of December 31, 2020 | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | 4 | | | $ | 5 | | | $ | (5) | | | $ | 4 | |
| | | | | | | | | | |
| | | | | | | | | | |
Money market mutual funds | | 41 | | | — | | | — | | | — | | | 41 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 200 | | | — | | | — | | | — | | | 200 | |
International government obligations | | — | | | 5 | | | — | | | — | | | 5 | |
Corporate obligations | | — | | | 73 | | | — | | | — | | | 73 | |
Municipal obligations | | — | | | 2 | | | — | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | | — | | | 6 | | | — | | | — | | | 6 | |
| | | | | | | | | | |
Equity securities: | | | | | | | | | | |
United States companies | | 381 | | | — | | | — | | | — | | | 381 | |
International companies | | 9 | | | — | | | — | | | — | | | 9 | |
Investment funds | | 17 | | | — | | | — | | | — | | | 17 | |
| | $ | 648 | | | $ | 90 | | | $ | 5 | | | $ | (5) | | | $ | 738 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | — | | | $ | (4) | | | $ | (3) | | | $ | 5 | | | $ | (2) | |
| | | | | | | | | | |
| | | | | | | | | | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $5 million and $— million as of December 31, 2021 and 2020, respectively.
|
| | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2018: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — |
| | $ | 4 |
| | $ | 2 |
| | $ | (3 | ) | | $ | 3 |
|
Money market mutual funds(2) | | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Debt securities: | | | | | | | | | | |
United States government obligations | | 187 |
| | — |
| | — |
| | — |
| | 187 |
|
International government obligations | | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
Corporate obligations | | — |
| | 46 |
| | — |
| | — |
| | 46 |
|
Municipal obligations | | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Agency, asset and mortgage-backed obligations | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Equity securities: | | | | | | | | | | |
United States companies | | 256 |
| | — |
| | — |
| | — |
| | 256 |
|
International companies | | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
Investment funds | | 10 |
| | — |
| | — |
| | — |
| | 10 |
|
| | $ | 461 |
| | $ | 57 |
| | $ | 2 |
| | $ | (3 | ) | | $ | 517 |
|
Liabilities: | | | | | | | | | | |
Commodity derivatives | | $ | — |
| | $ | (4 | ) | | $ | (2 | ) | | $ | 3 |
| | $ | (3 | ) |
Interest rate derivatives(3) | | — |
| | (19 | ) | | — |
| | — |
| | (19 | ) |
| | $ | — |
| | $ | (23 | ) | | $ | (2 | ) | | $ | 3 |
| | $ | (22 | ) |
| | | | | | | | | | |
As of December 31, 2017 | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — |
| | $ | 3 |
| | $ | 4 |
| | $ | (2 | ) | | $ | 5 |
|
Money market mutual funds(2) | | 133 |
| | — |
| | — |
| | — |
| | 133 |
|
Debt securities: | | | | | | | | | | |
United States government obligations | | 176 |
| | — |
| | — |
| | — |
| | 176 |
|
International government obligations | | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Corporate obligations | | — |
| | 36 |
| | — |
| | — |
| | 36 |
|
Municipal obligations | | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Equity securities: | | | | | | | | | | |
United States companies | | 288 |
| | — |
| | — |
| | — |
| | 288 |
|
International companies | | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
Investment funds | | 15 |
| | — |
| | — |
| | — |
| | 15 |
|
| | $ | 619 |
| | $ | 46 |
| | $ | 4 |
| | $ | (2 | ) | | $ | 667 |
|
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | — |
| | $ | (9 | ) | | $ | (1 | ) | | $ | 2 |
| | $ | (8 | ) |
| |
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $- million as of December 31, 2018 and 2017. |
| |
(2) | Amounts are included in cash and cash equivalents and investments and restricted cash and investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost. |
| |
(3) | The interest rate derivatives are interest rate locks related to MidAmerican Energy's January 2019 issuance of first mortgage bonds, at which time the interest rate locks were settled for $22 million. |
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities primarily accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
The following table reconciles the beginning and ending balances of MidAmerican Energy's assets measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Commodity Derivatives | | Auction Rate Securities |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | | | | |
Beginning balance | | $ | 3 |
| | $ | (2 | ) | | $ | (6 | ) | | $ | — |
| | $ | — |
| | $ | 26 |
|
Transfer to affiliate(1) | | — |
| | — |
| | (4 | ) | | — |
| | — |
| | — |
|
Changes included in earnings | | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
Changes in fair value recognized in OCI | | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
Changes in fair value recognized in net regulatory assets | | (3 | ) | | 2 |
| | (6 | ) | | — |
| | — |
| | — |
|
Redemptions | | — |
| | — |
| | — |
| | — |
| | — |
| | (35 | ) |
Settlements | | — |
| | 3 |
| | 14 |
| | — |
| | — |
| | — |
|
Ending balance | | $ | — |
| | $ | 3 |
| | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| |
(1) | On January 1, 2016, MidAmerican Energy transferred the assets and liabilities of its unregulated retail services business to a subsidiary of BHE. |
MidAmerican Energy's long-term debt is carried at cost on the Financial Statements. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,721 | | | $ | 9,037 | | | $ | 7,210 | | | $ | 9,130 | |
(13)Commitments and Contingencies
|
| | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 5,381 |
| | $ | 5,646 |
| | $ | 5,042 |
| | $ | 5,686 |
|
| |
(13) | Commitments and Contingencies |
Commitments
MidAmerican Energy had the following firm commitments that are not reflected on the Balance Sheet. Minimum payments as of December 31, 2018,2021, are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 2027 and | | |
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | | |
Coal and natural gas for generation | | $ | 127 | | | $ | 81 | | | $ | 55 | | | $ | 27 | | | $ | — | | | $ | — | | | $ | 290 | |
Electric capacity and transmission | | 32 | | | 32 | | | 32 | | | 32 | | | 32 | | | 25 | | | 185 | |
Natural gas contracts for gas operations | | 156 | | | 59 | | | 28 | | | 20 | | | 11 | | | 21 | | | 295 | |
Construction commitments | | 806 | | | 19 | | | 12 | | | 11 | | | 4 | | | — | | | 852 | |
Easements | | 40 | | | 41 | | | 42 | | | 43 | | | 44 | | | 1,574 | | | 1,784 | |
Maintenance, services and other | | 165 | | | 166 | | | 131 | | | 99 | | | 98 | | | 260 | | | 919 | |
| | $ | 1,326 | | | $ | 398 | | | $ | 300 | | | $ | 232 | | | $ | 189 | | | $ | 1,880 | | | $ | 4,325 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 2024 and | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | | |
Coal and natural gas for generation | | $ | 96 |
| | $ | 21 |
| | $ | 17 |
| | $ | 13 |
| | $ | 5 |
| | $ | — |
| | $ | 152 |
|
Electric capacity and transmission | | 29 |
| | 28 |
| | 26 |
| | 15 |
| | 7 |
| | 36 |
| | 141 |
|
Natural gas contracts for gas operations | | 145 |
| | 76 |
| | 59 |
| | 45 |
| | 23 |
| | 30 |
| | 378 |
|
Construction commitments | | 1,299 |
| | 28 |
| | 50 |
| | — |
| | — |
| | — |
| | 1,377 |
|
Easements and operating leases | | 27 |
| | 29 |
| | 29 |
| | 30 |
| | 30 |
| | 1,078 |
| | 1,223 |
|
Maintenance and services contracts | | 118 |
| | 196 |
| | 147 |
| | 143 |
| | 134 |
| | 224 |
| | 962 |
|
| | $ | 1,714 |
| | $ | 378 |
| | $ | 328 |
| | $ | 246 |
| | $ | 199 |
| | $ | 1,368 |
| | $ | 4,233 |
|
Coal, Natural Gas, Electric Capacity and Transmission Commitments
MidAmerican Energy has coal supply and related transportation and lime contracts for its coal-fueled generating facilities. MidAmerican Energy expects to supplement the coal contracts with additional contracts and spot market purchases to fulfill its future coal supply needs. Additionally, MidAmerican Energy has a natural gas transportation contract for a natural gas-fueled generating facility. The contracts have minimum payment commitments ranging through 2023.2025.
MidAmerican Energy has various natural gas supply and transportation contracts for its regulated natural gas operations that have minimum payment commitments ranging through 2037.
MidAmerican Energy has contracts to purchase electric capacity that have minimum payment commitments ranging through 2028. MidAmerican Energy also has contracts for the right to transmit electricity over other entities' transmission lines with minimum payment commitments ranging through 2022.2027.
Construction Commitments
MidAmerican Energy's firm construction commitments reflected in the table above consist primarily of contracts for the constructionrepowering and repoweringconstruction of wind-powered generating facilities in 2019.and solar-powered generating facilities and the settlement of AROs.
Easements and Operating Leases
MidAmerican Energy has non-cancelable easements with minimum payment commitments ranging through 2061 for land in Iowa on which certain of its assets, primarily wind-powered generating facilities, are located. MidAmerican Energy also has non-cancelable operating leases with minimum payment commitments ranging through 2024 primarily for office and other building space. These leases generally require MidAmerican Energy to pay for insurance, taxes and maintenance applicable to the leased property. A number of the leases contain renewal options for varying periods. Rent expense on non-cancelable operating leases totaled $3 million, $3 million and $4 million for 2018, 2017 and 2016, respectively.
Maintenance, Services and Other Contracts
MidAmerican Energy has other non-cancelable contracts primarily related to maintenance and services for various generating facilities with minimum payment commitments ranging through 2028.2030.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air and water quality, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Transmission Rates
MidAmerican Energy's wholesale transmission rates are set annually using FERC-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% return on equity ("ROE").ROE. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the base ROE effective January 2015. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and requiresrequired refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. It is uncertain whenIn November 2019, the FERC will rule onissued an order addressing the second complaint coveringand issues on appeal in the first complaint. The order established an ROE of 9.88% (10.38% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from February 2015 throughSeptember 2016 forward. In May 2016.2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of 10.02% (10.52% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. These orders continue to be subject to judicial appeal. MidAmerican Energy believes it is probable thatcannot predict the FERC will order a base ROE lower than 12.38% in the second complaintultimate outcome of these matters and, as of December 31, 2018,2021, has accrued a $10$8 million liability for refunds of amounts collected under the higher ROE from March 2015 through May 2016.during the periods covered by both complaints.
Legal Matters
MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
| |
(14) | Components of Accumulated Other Comprehensive Loss, Net |
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income, net of applicable income taxes, for the year ended December 31, 2016 (in millions):
|
| | | | | | | | | | | | |
| | Unrealized | | Unrealized | | Accumulated |
| | Losses on | | Losses | | Other |
| | Available-For-Sale | | on Cash Flow | | Comprehensive |
| | Securities | | Hedges | | Loss, Net |
| | | | | | |
Balance, December 31, 2015 | | $ | (3 | ) | | $ | (27 | ) | | $ | (30 | ) |
Other comprehensive income | | 3 |
| | — |
| | 3 |
|
Dividend of unregulated retail services business | | — |
| | 27 |
| | 27 |
|
Balance, December 31, 2016 | | $ | — |
| | $ | — |
| | $ | — |
|
(14) Revenue from Contracts with Customers
On January 1, 2016, MidAmerican Energy transferred the assets and liabilities of its unregulated retail services business to a subsidiary of BHE.
| |
(15) | Revenue from Contracts with Customers |
MidAmerican Energy uses a single five-step model to identify and recognizes revenue from contracts with customers ("recognize Customer Revenue")Revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The following table summarizes MidAmerican Energy's revenue by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 19,18, (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2021 |
| Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 718 | | | $ | 564 | | | $ | — | | | $ | 1,282 | |
Commercial | 327 | | | 223 | | | — | | | 550 | |
Industrial | 934 | | | 30 | | | — | | | 964 | |
Natural gas transportation services | — | | | 39 | | | — | | | 39 | |
Other retail | 149 | | | 3 | | | — | | | 152 | |
Total retail | 2,128 | | | 859 | | | — | | | 2,987 | |
Wholesale | 312 | | | 142 | | | — | | | 454 | |
Multi-value transmission projects | 58 | | | — | | | — | | | 58 | |
Other Customer Revenue | — | | | — | | | 15 | | | 15 | |
Total Customer Revenue | 2,498 | | | 1,001 | | | 15 | | | 3,514 | |
Other revenue | 31 | | | 2 | | | — | | | 33 | |
Total operating revenue | $ | 2,529 | | | $ | 1,003 | | | $ | 15 | | | $ | 3,547 | |
| | | | | | | |
| For the Year Ended December 31, 2020 |
| Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 685 | | | $ | 342 | | | $ | — | | | $ | 1,027 | |
Commercial | 304 | | | 111 | | | — | | | 415 | |
Industrial | 804 | | | 14 | | | — | | | 818 | |
Natural gas transportation services | — | | | 36 | | | — | | | 36 | |
Other retail | 131 | | | 2 | | | — | | | 133 | |
Total retail | 1,924 | | | 505 | | | — | | | 2,429 | |
Wholesale | 133 | | | 66 | | | — | | | 199 | |
Multi-value transmission projects | 60 | | | — | | | — | | | 60 | |
Other Customer Revenue | — | | | — | | | 8 | | | 8 | |
Total Customer Revenue | 2,117 | | | 571 | | | 8 | | | 2,696 | |
Other revenue | 22 | | | 2 | | | — | | | 24 | |
Total operating revenue | $ | 2,139 | | | $ | 573 | | | $ | 8 | | | $ | 2,720 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2019 |
| Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | Customer Revenue: | | | | | | | |
Retail: | | | | | | | | Retail: | |
Residential | $ | 696 |
| | $ | 421 |
| | $ | — |
| | $ | 1,117 |
| Residential | $ | 672 | | | $ | 383 | | | $ | — | | | $ | 1,055 | |
Commercial | 314 |
| | 153 |
| | — |
| | 467 |
| Commercial | 322 | | | 132 | | | — | | | 454 | |
Industrial | 758 |
| | 22 |
| | — |
| | 780 |
| Industrial | 799 | | | 17 | | | — | | | 816 | |
Natural gas transportation services | — |
| | 39 |
| | — |
| | 39 |
| Natural gas transportation services | — | | | 38 | | | — | | | 38 | |
Other retail | 147 |
| | 1 |
| | — |
| | 148 |
| Other retail | 145 | | | — | | | — | | | 145 | |
Total retail | 1,915 |
| | 636 |
| | — |
| | 2,551 |
| Total retail | 1,938 | | | 570 | | | — | | | 2,508 | |
Wholesale | 295 |
| | 116 |
| | — |
| | 411 |
| Wholesale | 221 | | | 88 | | | — | | | 309 | |
Multi-value transmission projects | 55 |
| | — |
| | — |
| | 55 |
| Multi-value transmission projects | 57 | | | — | | | — | | | 57 | |
Other Customer Revenue | — |
| | — |
| | 11 |
| | 11 |
| Other Customer Revenue | — | | | — | | | 28 | | | 28 | |
Total Customer Revenue | 2,265 |
| | 752 |
| | 11 |
| | 3,028 |
| Total Customer Revenue | 2,216 | | | 658 | | | 28 | | | 2,902 | |
Other revenue | 18 |
| | 2 |
| | 1 |
| | 21 |
| Other revenue | 21 | | | 2 | | | — | | | 23 | |
Total operating revenue | $ | 2,283 |
| | $ | 754 |
| | $ | 12 |
| | $ | 3,049 |
| Total operating revenue | $ | 2,237 | | | $ | 660 | | | $ | 28 | | | $ | 2,925 | |
Contract Assets and Liabilities
In the event one of the parties to a contract has performed before the other, MidAmerican Energy would recognize a contract asset or contract liability depending on the relationship between MidAmerican Energy's performance and the customer's payment. As of December 31, 2018, there were no contract assets or contract liabilities recorded on the Balance Sheets.
(16)(15)Other Income (Expense) - Other, Net
Other, net, as shown on the Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Non-service cost components of postretirement employee benefit plans | $ | 26 | | | $ | 24 | | | $ | 17 | |
Corporate-owned life insurance income | 21 | | | 16 | | | 24 | |
Gains on disposition of assets | — | | | 6 | | | — | |
| | | | | |
| | | | | |
Interest income and other, net | 6 | | | 6 | | | 9 | |
Total | $ | 53 | | | $ | 52 | | | $ | 50 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Non-service cost components of postretirement employee benefit plans | $ | 21 |
| | $ | 18 |
| | $ | 15 |
|
Corporate-owned life insurance income | 6 |
| | 13 |
| | 8 |
|
Gain on redemption of auction rate securities | — |
| | — |
| | 5 |
|
Interest income and other, net | 3 |
| | 6 |
| | 1 |
|
Total | $ | 30 |
| | $ | 37 |
| | $ | 29 |
|
(17)(16)Supplemental Cash Flow Disclosures
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 20182021 and 2017,2020 consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements.wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 20182021 and 20172020 as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 232 | | | $ | 38 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 239 | | | $ | 45 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
Cash and cash equivalents | $ | — |
| | $ | 172 |
|
Restricted cash and cash equivalents in other current assets | 56 |
| | 110 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 56 |
| | $ | 282 |
|
The summary of supplemental cash flow disclosures as of and for the years ending December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 279 | | | $ | 286 | | | $ | 224 | |
Income taxes received, net | $ | 746 | | | $ | 709 | | | $ | 450 | |
| | | | | |
Supplemental disclosure of non-cash investing transactions: | | | | | |
Accounts payable related to utility plant additions | $ | 257 | | | $ | 227 | | | $ | 337 | |
(17)Related Party Transactions
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Supplemental cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 198 |
| | $ | 193 |
| | $ | 181 |
|
Income taxes received, net | $ | 494 |
| | $ | 465 |
| | $ | 601 |
|
| | | | | |
Supplemental disclosure of non-cash investing transactions: | | | | | |
Accounts payable related to utility plant additions | $ | 371 |
| | $ | 224 |
| | $ | 131 |
|
Dividend of unregulated retail services business | $ | — |
| | $ | — |
| | $ | 90 |
|
| |
(18) | Related Party Transactions |
The companies identified as affiliates of MidAmerican Energy are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in servicein-service agreements between MidAmerican Energy and the affiliates.
MidAmerican Energy is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for general costs, such as insurance and building rent, and for employee wages, benefits and costs related to corporate functions such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $51$66 million, $53$47 million and $41$43 million for 2018, 20172021, 2020 and 2016,2019, respectively. Additionally, in 2018, MidAmerican Energy received $15 million from BHE for the transfer of corporate aircraft.
MidAmerican Energy reimbursed BHE in the amount of $11$72 million, $9$15 million and $6$14 million in 2018, 20172021, 2020 and 2016,2019, respectively, for its share of corporate expenses.
MidAmerican Energy purchases, in the normal course of business at either tariffed or market prices, natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE, and coal transportation services from BNSF Railway Company, an indirect wholly owned subsidiary of Berkshire Hathaway, in the normal course of business at either tariffed or market prices.Hathaway. These purchases totaled $127$132 million, $122$129 million and $135$139 million in 2018, 20172021, 2020 and 2016,2019, respectively. Additionally, in 2020, MidAmerican Energy paid $7 million to BHE Renewables, LLC, a wholly owned subsidiary of BHE, for the purchase of wind turbine components.
MidAmerican Energy had accounts receivable from affiliates of $8$10 million and $9$12 million as of December 31, 20182021 and 2017,2020, respectively, that are included in receivablesother current assets on the Balance Sheets. MidAmerican Energy also had accounts payable to affiliates of $12$17 million and $16$13 million as of December 31, 20182021 and 2017,2020, respectively, that are included in accounts payable on the Balance Sheets.
MidAmerican Energy is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, MidAmerican Energy had a payable toreceivable from BHE of $156$79 million as of December 31, 2018,2021, and a receivable frompayable to BHE of $51$14 million as of December 31, 2017.2020. MidAmerican Energy received net cash receiptspayments for federal and state income taxes from BHE totaling $494$746 million, $465$709 million and $601$450 million for the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
MidAmerican Energy recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MidAmerican Energy's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates.affiliates, as well as the initial liabilities associated with BHE's acquisition of GT&S. MidAmerican Energy adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $20$124 million and $16$146 million as of December 31, 20182021 and 2017,2020, respectively, and similarare included in other assets on the Balance Sheets. Similar amounts payable to affiliates totaled $36$63 million and $45$49 million as of December 31, 20182021 and 2017, respectively.2020, respectively, and are included in other long-term liabilities on the Balance Sheets. See Note 10 for further information pertaining to pension and postretirement accounting.
(19)(18)Segment Information
MidAmerican Energy has identified two2 reportable operating segments: regulated electric and regulated natural gas. The previously reported nonregulated energy segment consisted substantially of MidAmerican Energy's unregulated retail services business, which was transferred to a subsidiary of BHE and is excluded from the information below related to the statements of operations for all periods presented. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. Refer to Note 9 for a discussion of items affecting income tax (benefit) expense for the regulated electric and natural gas operating segments.
The following tables provide information on a reportable segment basis (in millions):
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,529 | | | $ | 2,139 | | | $ | 2,237 | |
Regulated natural gas | 1,003 | | | 573 | | | 660 | |
Other | 15 | | | 8 | | | 28 | |
Total operating revenue | $ | 3,547 | | | $ | 2,720 | | | $ | 2,925 | |
| | | | | |
Depreciation and amortization: | | | | | |
Regulated electric | $ | 861 | | | $ | 667 | | | $ | 593 | |
Regulated natural gas | 53 | | | 49 | | | 46 | |
Total depreciation and amortization | $ | 914 | | | $ | 716 | | | $ | 639 | |
| | | | | |
Operating income: | | | | | |
Regulated electric | $ | 358 | | | $ | 384 | | | $ | 473 | |
Regulated natural gas | 58 | | | 64 | | | 71 | |
Other | — | | | — | | | 4 | |
Total operating income | $ | 416 | | | $ | 448 | | | $ | 548 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Interest expense: | | | | | |
Regulated electric | $ | 279 | | | $ | 281 | | | $ | 259 | |
Regulated natural gas | 23 | | | 23 | | | 22 | |
Total interest expense | $ | 302 | | | $ | 304 | | | $ | 281 | |
| | | | | |
| | | | | |
| | | | | | | | | | Years Ended December 31, |
| Years Ended December 31, | | 2021 | | 2020 | | 2019 |
| 2018 | | 2017 | | 2016 | |
Operating revenue: | | | | | | |
Income tax (benefit) expense: | | Income tax (benefit) expense: | | | | | |
Regulated electric | $ | 2,283 |
| | $ | 2,108 |
| | $ | 1,985 |
| Regulated electric | $ | (677) | | | $ | (584) | | | $ | (384) | |
Regulated natural gas | 754 |
| | 719 |
| | 637 |
| Regulated natural gas | 3 | | | 14 | | | 12 | |
Other | 12 |
| | 10 |
| | 3 |
| Other | (1) | | | — | | | 1 | |
Total operating revenue | $ | 3,049 |
| | $ | 2,837 |
| | $ | 2,625 |
| |
Total income tax (benefit) expense | | Total income tax (benefit) expense | $ | (675) | | | $ | (570) | | | $ | (371) | |
| | | | | | | | | | | |
Depreciation and amortization: | | | | | | |
Net income: | | Net income: | |
Regulated electric | $ | 565 |
| | $ | 458 |
| | $ | 436 |
| Regulated electric | $ | 844 | | | $ | 780 | | | $ | 739 | |
Regulated natural gas | 44 |
| | 42 |
| | 43 |
| Regulated natural gas | 50 | | | 45 | | | 52 | |
Total depreciation and amortization | $ | 609 |
| | $ | 500 |
| | $ | 479 |
| |
Other | | Other | — | | | 1 | | | 2 | |
Net income | | Net income | $ | 894 | | | $ | 826 | | | $ | 793 | |
| | | | | | | | | | | |
Capital expenditures: | | Capital expenditures: | |
Regulated electric | | Regulated electric | $ | 1,806 | | | $ | 1,704 | | | $ | 2,684 | |
Regulated natural gas | | Regulated natural gas | 106 | | | 132 | | | 126 | |
Total capital expenditures | | Total capital expenditures | $ | 1,912 | | | $ | 1,836 | | | $ | 2,810 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Total assets: | | | | | |
Regulated electric | $ | 21,385 | | | $ | 19,892 | | | $ | 19,093 | |
Regulated natural gas | 1,871 | | | 1,544 | | | 1,468 | |
Other | 1 | | | 1 | | | 3 | |
Total assets | $ | 23,257 | | | $ | 21,437 | | | $ | 20,564 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating income: | | | | | |
Regulated electric | $ | 469 |
| | $ | 472 |
| | $ | 486 |
|
Regulated natural gas | 81 |
| | 72 |
| | 64 |
|
Other | 1 |
| | (1 | ) | | — |
|
Total operating income | $ | 551 |
| | $ | 543 |
| | $ | 550 |
|
| | | | | |
Interest expense: | | | | | |
Regulated electric | $ | 208 |
| | $ | 196 |
| | $ | 178 |
|
Regulated natural gas | 19 |
| | 18 |
| | 18 |
|
Total interest expense | $ | 227 |
| | $ | 214 |
| | $ | 196 |
|
| | | | | |
Income tax (benefit) expense: | | | | | |
Regulated electric | $ | (273 | ) | | $ | (212 | ) | | $ | (156 | ) |
Regulated natural gas | 16 |
| | 29 |
| | 22 |
|
Other | 2 |
| | — |
| | 2 |
|
Total income tax (benefit) expense | $ | (255 | ) | | $ | (183 | ) | | $ | (132 | ) |
| | | | | |
Net income: | | | | | |
Regulated electric | $ | 628 |
| | $ | 570 |
| | $ | 512 |
|
Regulated natural gas | 54 |
| | 35 |
| | 32 |
|
Other | — |
| | — |
| | (2 | ) |
Net income | $ | 682 |
| | $ | 605 |
| | $ | 542 |
|
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Capital expenditures: | | | | | |
Regulated electric | $ | 2,223 |
| | $ | 1,686 |
| | $ | 1,564 |
|
Regulated natural gas | 109 |
| | 87 |
| | 72 |
|
Total capital expenditures | $ | 2,332 |
| | $ | 1,773 |
| | $ | 1,636 |
|
| | | | | |
| As of December 31, |
| 2018 | | 2017 | | 2016 |
Total assets: | | | | | |
Regulated electric | $ | 16,511 |
| | $ | 14,914 |
| | $ | 14,113 |
|
Regulated natural gas | 1,406 |
| | 1,403 |
| | 1,345 |
|
Other | 3 |
| | 1 |
| | 1 |
|
Total assets | $ | 17,920 |
| | $ | 16,318 |
| | $ | 15,459 |
|
(20)Unaudited Quarterly Operating Results (in millions)
|
| | | | | | | | | | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2018 | | 2018 | | 2018 | | 2018 |
| | | | | | | |
Operating revenue | $ | 746 |
| | $ | 717 |
| | $ | 832 |
| | $ | 754 |
|
Operating income | 79 |
| | 87 |
| | 278 |
| | 107 |
|
Net income (loss) | 106 |
| | 106 |
| | 483 |
| | (13 | ) |
| | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2017 | | 2017 | | 2017 | | 2017 |
| | | | | | | |
Operating revenue | $ | 695 |
| | $ | 658 |
| | $ | 813 |
| | $ | 671 |
|
Operating income | 102 |
| | 130 |
| | 284 |
| | 27 |
|
Net income | 105 |
| | 134 |
| | 385 |
| | (19 | ) |
Quarterly operating results are affected by, among other things, MidAmerican Energy's seasonal retail electricity prices, the timing of recognition of federal renewable electricity production tax credits related to MidAmerican Energy's wind-powered generating facilities and the seasonal impact of weather on electricity and natural gas sales.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Member of
MidAmerican Funding, LLC
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of December 31, 20182021 and 2017,2020, the related consolidated statements of operations, comprehensive income, changes in member's equity, and cash flows for each of the three years in the period ended December 31, 2018, and2021, the related notes and the schedulesschedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MidAmerican Funding as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of MidAmerican Funding's management. Our responsibility is to express an opinion on MidAmerican Funding's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MidAmerican Funding is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MidAmerican Funding's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 5 to the financial statements
Critical Audit Matter Description
MidAmerican Funding is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where MidAmerican Funding operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense and income tax benefit.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow MidAmerican Funding an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While MidAmerican Funding has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit MidAmerican Funding's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated MidAmerican Funding's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected MidAmerican Funding's filings with the Commissions and the filings with the Commissions by intervenors that may impact MidAmerican Funding's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
February 22, 201925, 2022
We have served as MidAmerican Funding's auditor since 1999.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
| | | |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 233 | | | $ | 39 | |
Trade receivables, net | 526 | | | 234 | |
Income tax receivable | 80 | | | — | |
Inventories | 234 | | | 278 | |
Other current assets | 123 | | | 74 | |
Total current assets | 1,196 | | | 625 | |
| | | |
Property, plant and equipment, net | 20,302 | | | 19,279 | |
Goodwill | 1,270 | | | 1,270 | |
Regulatory assets | 473 | | | 392 | |
Investments and restricted investments | 1,028 | | | 913 | |
Other assets | 262 | | | 232 | |
| | | |
Total assets | $ | 24,531 | | | $ | 22,711 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 1 |
| | $ | 172 |
|
Accounts receivable, net | 365 |
| | 348 |
|
Income taxes receivable | — |
| | 64 |
|
Inventories | 204 |
| | 245 |
|
Other current assets | 89 |
| | 134 |
|
Total current assets | 659 |
| | 963 |
|
| | | |
Property, plant and equipment, net | 16,171 |
| | 14,221 |
|
Goodwill | 1,270 |
| | 1,270 |
|
Regulatory assets | 273 |
| | 204 |
|
Investments and restricted investments | 710 |
| | 730 |
|
Other assets | 119 |
| | 233 |
|
| | | |
Total assets | $ | 19,202 |
| | $ | 17,621 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
| | | |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 531 | | | $ | 408 | |
Accrued interest | 89 | | | 83 | |
Accrued property, income and other taxes | 158 | | | 161 | |
Note payable to affiliate | 189 | | | 177 | |
| | | |
| | | |
Other current liabilities | 146 | | | 183 | |
Total current liabilities | 1,113 | | | 1,012 | |
| | | |
Long-term debt | 7,961 | | | 7,450 | |
Regulatory liabilities | 1,080 | | | 1,111 | |
Deferred income taxes | 3,387 | | | 3,052 | |
Asset retirement obligations | 714 | | | 709 | |
Other long-term liabilities | 475 | | | 458 | |
Total liabilities | 14,730 | | | 13,792 | |
| | | |
Commitments and contingencies (Note 13) | 0 | | 0 |
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 | | | 1,679 | |
Retained earnings | 8,122 | | | 7,240 | |
| | | |
Total member's equity | 9,801 | | | 8,919 | |
| | | |
Total liabilities and member's equity | $ | 24,531 | | | $ | 22,711 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 575 |
| | $ | 451 |
|
Accrued interest | 58 |
| | 53 |
|
Accrued property, income and other taxes | 300 |
| | 133 |
|
Note payable to affiliate | 156 |
| | 164 |
|
Short-term debt | 240 |
| | — |
|
Current portion of long-term debt | 500 |
| | 350 |
|
Other current liabilities | 122 |
| | 128 |
|
Total current liabilities | 1,951 |
| | 1,279 |
|
| | | |
Long-term debt | 5,121 |
| | 4,932 |
|
Regulatory liabilities | 1,620 |
| | 1,661 |
|
Deferred income taxes | 2,319 |
| | 2,235 |
|
Asset retirement obligations | 552 |
| | 528 |
|
Other long-term liabilities | 310 |
| | 326 |
|
Total liabilities | 11,873 |
| | 10,961 |
|
| | | |
Commitments and contingencies (Note 13) |
| |
|
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 |
| | 1,679 |
|
Retained earnings | 5,650 |
| | 4,981 |
|
Total member's equity | 7,329 |
| | 6,660 |
|
| | | |
Total liabilities and member's equity | $ | 19,202 |
| | $ | 17,621 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,529 | | | $ | 2,139 | | | $ | 2,237 | |
Regulated natural gas and other | 1,018 | | | 589 | | | 690 | |
Total operating revenue | 3,547 | | | 2,728 | | | 2,927 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 539 | | | 339 | | | 399 | |
Cost of natural gas purchased for resale and other | 761 | | | 329 | | | 412 | |
Operations and maintenance | 775 | | | 755 | | | 801 | |
Depreciation and amortization | 914 | | | 716 | | | 639 | |
Property and other taxes | 142 | | | 135 | | | 127 | |
Total operating expenses | 3,131 | | | 2,274 | | | 2,378 | |
| | | | | |
Operating income | 416 | | | 454 | | | 549 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (319) | | | (322) | | | (302) | |
Allowance for borrowed funds | 13 | | | 15 | | | 27 | |
Allowance for equity funds | 39 | | | 45 | | | 78 | |
Other, net | 54 | | | 52 | | | 52 | |
Total other income (expense) | (213) | | | (210) | | | (145) | |
| | | | | |
Income before income tax benefit | 203 | | | 244 | | | 404 | |
Income tax benefit | (680) | | | (574) | | | (377) | |
| | | | | |
Net income | $ | 883 | | | $ | 818 | | | $ | 781 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,283 |
| | $ | 2,108 |
| | $ | 1,985 |
|
Regulated natural gas and other | 770 |
| | 738 |
| | 646 |
|
Total operating revenue | 3,053 |
| | 2,846 |
| | 2,631 |
|
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 487 |
| | 434 |
| | 409 |
|
Cost of natural gas purchased for resale and other | 469 |
| | 447 |
| | 371 |
|
Operations and maintenance | 813 |
| | 802 |
| | 709 |
|
Depreciation and amortization | 609 |
| | 500 |
| | 479 |
|
Property and other taxes | 125 |
| | 119 |
| | 112 |
|
Total operating expenses | 2,503 |
| | 2,302 |
| | 2,080 |
|
| | | | | |
Operating income | 550 |
| | 544 |
| | 551 |
|
| | | | | |
Other income (expense): | | | | | |
Interest expense | (247 | ) | | (237 | ) | | (219 | ) |
Allowance for borrowed funds | 20 |
| | 15 |
| | 8 |
|
Allowance for equity funds | 53 |
| | 41 |
| | 19 |
|
Other, net | 31 |
| | 9 |
| | 34 |
|
Total other income (expense) | (143 | ) | | (172 | ) | | (158 | ) |
| | | | | |
Income before income tax benefit | 407 |
| | 372 |
| | 393 |
|
Income tax benefit | (262 | ) | | (202 | ) | | (139 | ) |
| | | | | |
Net income | $ | 669 |
| | $ | 574 |
| | $ | 532 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 669 |
| | $ | 574 |
| | $ | 532 |
|
| | | | | |
Other comprehensive income, net of tax: | | | | | |
Unrealized gains on marketable securities, net of tax of $-, $- and $1 | — |
| | — |
| | 3 |
|
| | | | | |
Comprehensive income | $ | 669 |
| | $ | 574 |
| | $ | 535 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Paid-in Capital | | Retained Earnings | | Total Member's Equity |
| | | | | |
Balance, December 31, 2018 | $ | 1,679 | | | $ | 5,650 | | | $ | 7,329 | |
Net income | — | | | 781 | | | 781 | |
Distribution to member | — | | | (8) | | | (8) | |
Other equity transactions | — | | | (1) | | | (1) | |
Balance, December 31, 2019 | 1,679 | | | 6,422 | | | 8,101 | |
Net income | — | | | 818 | | | 818 | |
| | | | | |
| | | | | |
Balance, December 31, 2020 | 1,679 | | | 7,240 | | | 8,919 | |
Net income | — | | | 883 | | | 883 | |
Other equity transactions | — | | | (1) | | | (1) | |
Balance, December 31, 2021 | $ | 1,679 | | | $ | 8,122 | | | $ | 9,801 | |
|
| | | | | | | | | | | | | | | |
| | | | | Accumulated Other Comprehensive Loss, Net | | |
| | | | | | |
| Paid-in Capital | | Retained Earnings | | | Total Member's Equity |
| | | | | | | |
Balance, December 31, 2015 | $ | 1,679 |
| | $ | 3,876 |
| | $ | (30 | ) | | $ | 5,525 |
|
Net income | — |
| | 532 |
| | — |
| | 532 |
|
Other comprehensive income | — |
| | — |
| | 3 |
| | 3 |
|
Transfer unregulated retail services business to affiliate | — |
| | — |
| | 27 |
| | 27 |
|
Other equity transactions | — |
| | (1 | ) | | — |
| | (1 | ) |
Balance, December 31, 2016 | 1,679 |
| | 4,407 |
| | — |
| | 6,086 |
|
Net income | — |
| | 574 |
| | — |
| | 574 |
|
Balance, December 31, 2017 | 1,679 |
| | 4,981 |
| | — |
| | 6,660 |
|
Net income | — |
| | 669 |
| | — |
| | 669 |
|
Balance, December 31, 2018 | $ | 1,679 |
| | $ | 5,650 |
| | $ | — |
| | $ | 7,329 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 883 | | | $ | 818 | | | $ | 781 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 914 | | | 716 | | | 639 | |
Amortization of utility plant to other operating expenses | 34 | | | 34 | | | 33 | |
Allowance for equity funds | (39) | | | (45) | | | (78) | |
Deferred income taxes and amortization of investment tax credits | 153 | | | 211 | | | 152 | |
| | | | | |
Settlements of asset retirement obligations | (103) | | | (124) | | | (14) | |
Other, net | 21 | | | (17) | | | 5 | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | (293) | | | 48 | | | 56 | |
Inventories | 44 | | | (52) | | | (22) | |
| | | | | |
Pension and other postretirement benefit plans, net | (4) | | | (19) | | | (10) | |
Accrued property, income and other taxes, net | (71) | | | (66) | | | (74) | |
Accounts payable and other liabilities | 66 | | | 32 | | | 7 | |
Net cash flows from operating activities | 1,605 | | | 1,536 | | | 1,475 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (1,912) | | | (1,836) | | | (2,810) | |
Purchases of marketable securities | (213) | | | (281) | | | (156) | |
Proceeds from sales of marketable securities | 207 | | | 269 | | | 138 | |
Proceeds from sales of other investments | — | | | 3 | | | 1 | |
Other investment proceeds | 1 | | | 9 | | | 13 | |
Other, net | 5 | | | 11 | | | 13 | |
Net cash flows from investing activities | (1,912) | | | (1,825) | | | (2,801) | |
| | | | | |
Cash flows from financing activities: | | | | | |
| | | | | |
Proceeds from long-term debt | 492 | | | — | | | 2,326 | |
Repayments of long-term debt | (1) | | | — | | | (500) | |
Net change in note payable to affiliate | 12 | | | 5 | | | 15 | |
Net repayments of short-term debt | — | | | — | | | (240) | |
Other, net | (2) | | | (1) | | | (1) | |
Net cash flows from financing activities | 501 | | | 4 | | | 1,600 | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 194 | | | (285) | | | 274 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of year | 46 | | | 331 | | | 57 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of year | $ | 240 | | | $ | 46 | | | $ | 331 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Cash flows from operating activities: | | | | | |
Net income | $ | 669 |
| | $ | 574 |
| | $ | 532 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
Loss on other items | — |
| | 29 |
| | — |
|
Depreciation and amortization | 609 |
| | 500 |
| | 479 |
|
Amortization of utility plant to other operating expenses | 34 |
| | 34 |
| | 37 |
|
Allowance for equity funds | (53 | ) | | (41 | ) | | (19 | ) |
Deferred income taxes and amortization of investment tax credits | 32 |
| | 334 |
| | 362 |
|
Other, net | 16 |
| | (14 | ) | | (63 | ) |
Changes in other operating assets and liabilities: | | | | | |
Accounts receivable and other assets | (19 | ) | | (62 | ) | | (60 | ) |
Inventories | 41 |
| | 19 |
| | (27 | ) |
Derivative collateral, net | (1 | ) | | 2 |
| | 5 |
|
Contributions to pension and other postretirement benefit plans, net | (13 | ) | | (11 | ) | | (6 | ) |
Accrued property, income and other taxes, net | 230 |
| | (54 | ) | | 107 |
|
Accounts payable and other liabilities | (29 | ) | | 70 |
| | 46 |
|
Net cash flows from operating activities | 1,516 |
| | 1,380 |
| | 1,393 |
|
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (2,332 | ) | | (1,773 | ) | | (1,636 | ) |
Purchases of marketable securities | (263 | ) | | (143 | ) | | (138 | ) |
Proceeds from sales of marketable securities | 223 |
| | 137 |
| | 158 |
|
Proceeds from sales of other investments | 17 |
| | 2 |
| | 2 |
|
Other investment proceeds | 15 |
| | 1 |
| | — |
|
Other, net | 30 |
| | (3 | ) | | 10 |
|
Net cash flows from investing activities | (2,310 | ) | | (1,779 | ) | | (1,604 | ) |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 687 |
| | 990 |
| | 62 |
|
Repayments of long-term debt | (350 | ) | | (341 | ) | | (38 | ) |
Net change in note payable to affiliate | (8 | ) | | 133 |
| | 9 |
|
Net proceeds from (repayments of) short-term debt | 240 |
| | (99 | ) | | 99 |
|
Tender offer premium paid | — |
| | (29 | ) | | — |
|
Other, net | — |
| | — |
| | 1 |
|
Net cash flows from financing activities | 569 |
| | 654 |
| | 133 |
|
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (225 | ) | | 255 |
| | (78 | ) |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of year | 282 |
| | 27 |
| | 105 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of year | $ | 57 |
| | $ | 282 |
| | $ | 27 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
(1) | Organization and Operations
|
(1)Organization and Operations
MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries and related corporate services.subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations. Direct,operations, and its direct, wholly owned nonregulated subsidiaries of MHC aresubsidiary is Midwest Capital Group, Inc. ("Midwest Capital Group") and MEC Construction Services Co..
| |
(2) | Summary of Significant Accounting Policies
|
(2) Summary of Significant Accounting Policies
In addition to the following significant accounting policies, refer to Note 2 of MidAmerican Energy's Notes to Financial Statements for significant accounting policies of MidAmerican Funding.
Basis ofConsolidation and Presentation
The Consolidated Financial Statements include the accounts of MidAmerican Funding and its subsidiaries in which it held a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated, other than those between rate-regulated operations. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired when MidAmerican Funding purchased MHC. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, MidAmerican Funding estimates the fair value of theits reporting unit.units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MidAmerican Funding uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. In estimating future cash flows, MidAmerican Funding incorporates current market information, as well as historical factors. As such, theThe determination of fair value incorporates significant unobservable inputs. During 2018, 20172021, 2020 and 2016,2019, MidAmerican Funding did not record any goodwill impairments.
(3) Property, Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had nonregulated property gross of $24$1 million and $— million as of December 31, 20182021 and 2017, and related accumulated depreciation and amortization of $12 million and $10 million as of December 31, 2018 and 2017, respectively, which consisted primarily of a corporate aircraft owned by MHC.2020, respectively.
| |
(4) | Jointly Owned Utility Facilities |
(4)Jointly Owned Utility Facilities
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
(5)Regulatory Matters
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
| |
(6) | Investments and Restricted Investments |
(6)Investments and Restricted Investments
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.Statements. In addition to MidAmerican Energy's investments and restricted investments, MHC had corporate-owned life insurance policies in a Rabbi trust owned by MHC with a total cash surrender value of $2 million as of December 31, 20182021 and 2017.2020.
311
| |
(7) | Short-Term Debt and Credit Facilities |
(7)Short-term Debt and Credit Facilities
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's credit facilities, MHC has a $4 million unsecured credit facility, which expires in June 20192022 and has a variable interest rate based on the Eurodollar rate plus a spread. As of December 31, 20182021 and 2017,2020, there were no borrowings outstanding under this credit facility. As of December 31, 2018,2021, MHC was in compliance with the covenants of its credit facility.
(8)Long-TermLong-term Debt
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements for detail and a discussion of its long-term debt. In addition to MidAmerican Energy's annual repayments of long-term debt, MidAmerican Funding parent company has $239 million of 6.927% Senior Bonds due in 2029, with a carrying value of $240 million as of December 31, 20182021 and 2017. In December 2017, MidAmerican Funding redeemed through a tender offer a portion of its 6.927% Senior Bonds. A charge of $29 million for the total premium is included in other income (expense) on the Consolidated Statement of Operations.2020.
The MidAmerican Funding parent company long-term debt is secured by a pledge of the common stock of MHC. See Item 15(c) for the Consolidated Financial Statements of MHC Inc. and subsidiaries. The bonds are the direct senior secured obligations of MidAmerican Funding and effectively rank junior to all indebtedness and other liabilities of the direct and indirect subsidiaries of MidAmerican Funding, to the extent of the assets of these subsidiaries. MidAmerican Funding may redeem the bonds in whole or in part at any time at a redemption price equal to the sum of any accrued and unpaid interest to the date of redemption and the greater of (1) 100% of the principal amount of the bonds or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the bonds, discounted to the date of redemption on a semiannual basis at the treasury yield plus 25 basis points.
MidAmerican Funding parent company long-term debt is secured by a pledge of the common stock of MHC, which is not publicly traded. In the event of any triggering event under the related debt indenture, the common stock of MHC would be available to satisfy the applicable debt obligations. Triggering events include, among other specified circumstances, (1) default on the payment of interest for 30 days or principal for three days; (2) a material default in the performance of any material covenants or obligations in the indenture continuing for a period of 90 days after written notice in accordance with the indenture; or (3) the failure generally of MidAmerican Funding or any significant subsidiary to pay its debts when due.
Subsidiaries of MidAmerican Funding must make payments on their own indebtedness before making distributions to MidAmerican Funding. Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements for a discussion of utility regulatory restrictions affecting distributions from MidAmerican Energy. As a result of the utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, MidAmerican Funding had restricted net assets of $3.9$5.6 billion as of December 31, 2018.2021.
As of December 31, 2018,2021, MidAmerican Funding was in compliance with all of its applicable long-term debt covenants.
Each of MidAmerican Funding's direct or indirect subsidiaries is organized as a legal entity separate and apart from MidAmerican Funding and its other subsidiaries. It should not be assumed that any asset of any subsidiary of MidAmerican Funding will be available to satisfy the obligations of MidAmerican Funding or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MidAmerican Funding, one of its subsidiaries or affiliates thereof.
(9)Income Taxes
Tax Cuts and Jobs Act
On December 22, 2017, the Tax Cuts and Jobs Act ("2017 Tax Reform") was signed into law, which impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018 and limitations on bonus depreciation for utility property. Accounting principles generally accepted in the United States of America ("GAAP") require the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, MidAmerican Funding reduced deferred income tax liabilities $1,822 million. As it is probable the change in deferred taxes for the MidAmerican Funding's regulated businesses will be passed back to customers through regulatory mechanisms, MidAmerican Funding increased net regulatory liabilities by $1,845 million.
In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. On December 31, 2017, MidAmerican Funding recorded the impacts of 2017 Tax Reform and believed all the impacts to be complete with the exception of interpretations of the bonus depreciation rules. MidAmerican Funding determined the amounts recorded and the interpretations relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. MidAmerican Funding believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, MidAmerican Funding recorded a current tax benefit of $27 million and a deferred tax expense of $28 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform, MidAmerican Funding reduced the associated deferred income tax liabilities $12 million and increased regulatory liabilities by the same amount.
MidAmerican Funding's income tax benefit from continuing operations consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Current: | | | | | |
Federal | $ | (739) | | | $ | (689) | | | $ | (480) | |
State | (94) | | | (96) | | | (49) | |
| (833) | | | (785) | | | (529) | |
Deferred: | | | | | |
Federal | 189 | | | 204 | | | 164 | |
State | (35) | | | 8 | | | (11) | |
| 154 | | | 212 | | | 153 | |
| | | | | |
Investment tax credits | (1) | | | (1) | | | (1) | |
Total | $ | (680) | | | $ | (574) | | | $ | (377) | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Current: | | | | | |
Federal | $ | (280 | ) | | $ | (505 | ) | | $ | (485 | ) |
State | (14 | ) | | (31 | ) | | (16 | ) |
| (294 | ) | | (536 | ) | | (501 | ) |
Deferred: | | | | | |
Federal | 42 |
| | 338 |
| | 367 |
|
State | (9 | ) | | (3 | ) | | (4 | ) |
| 33 |
| | 335 |
| | 363 |
|
| | | | | |
Investment tax credits | (1 | ) | | (1 | ) | | (1 | ) |
Total | $ | (262 | ) | | $ | (202 | ) | | $ | (139 | ) |
Iowa Senate File 2417
In May 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% and eliminates corporate federal deductibility, both for tax years starting in 2021. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of Iowa Senate File 2417, MidAmerican Funding reduced net deferred income tax liabilities $54 million and decreased deferred income tax benefit by $2 million. As it is probable the change in deferred taxes for MidAmerican Energy will be passed back to customers through regulatory mechanisms, MidAmerican Funding increased net regulatory liabilities by $56 million.
A reconciliation of the federal statutory income tax rate to MidAmerican Funding's the effective income tax rate applicable to income before income tax benefit from continuing operations is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (283) | | | (209) | | | (94) | |
State income tax, net of federal income tax benefit | (50) | | | (29) | | | (12) | |
Effects of ratemaking | (21) | | | (17) | | | (8) | |
Other, net | (2) | | | (1) | | | — | |
Effective income tax rate | (335) | % | | (235) | % | | (93) | % |
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
Income tax credits | (76 | ) | | (77 | ) | | (64 | ) |
State income tax, net of federal income tax benefit | (4 | ) | | (6 | ) | | (3 | ) |
Effects of ratemaking | (6 | ) | | (8 | ) | | (3 | ) |
2017 Tax Reform | 1 |
| | 3 |
| | — |
|
Other, net | — |
| | (1 | ) | | — |
|
Effective income tax rate | (64 | )% | | (54 | )% | | (35 | )% |
Income tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity production tax creditsPTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
MidAmerican Funding's net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 240 | | | $ | 288 | |
Asset retirement obligations | 220 | | | 229 | |
State carryforwards | 55 | | | 52 | |
Employee benefits | 26 | | | 43 | |
| | | |
Other | 30 | | | 40 | |
Total deferred income tax assets | 571 | | | 652 | |
Valuation allowances | (1) | | | (25) | |
Total deferred income tax assets, net | 570 | | | 627 | |
| | | |
Deferred income tax liabilities: | | | |
Depreciable property | (3,843) | | | (3,583) | |
Regulatory assets | (112) | | | (97) | |
Other | (2) | | | 1 | |
Total deferred income tax liabilities | (3,957) | | | (3,679) | |
| | | |
Net deferred income tax liability | $ | (3,387) | | | $ | (3,052) | |
|
| | | | | | | |
| 2018 | | 2017 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 405 |
| | $ | 443 |
|
Asset retirement obligations | 164 |
| | 160 |
|
Employee benefits | 47 |
| | 45 |
|
Other | 85 |
| | 62 |
|
Total deferred income tax assets | 701 |
| | 710 |
|
| | | |
Deferred income tax liabilities: | | | |
Depreciable property | (2,947 | ) | | (2,868 | ) |
Regulatory assets | (62 | ) | | (42 | ) |
Other | (11 | ) | | (35 | ) |
Total deferred income tax liabilities | (3,020 | ) | | (2,945 | ) |
| | | |
Net deferred income tax liability | $ | (2,319 | ) | | $ | (2,235 | ) |
As of December 31, 2018,2021, MidAmerican Funding has available $44 million ofFunding's state tax carryforwards, principally related to $655$823 million of net operating losses, that expire at various intervals between 20192022 and 2037.2040.
The United States Internal Revenue Service has closed or effectively settled its examination MidAmerican Funding’sFunding's income tax returns through December 31, 2011.2013. The statute of limitations for MidAmerican Funding’sFunding's state income tax returns have expired through December 31, 2009, with the exception of Iowa2011, for Michigan and Illinois, for which the statute of limitations have expiredNebraska, and through December 31, 2014,2017, for Illinois, Indiana, Iowa, Kansas and Missouri, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
A reconciliation of the beginning and ending balances of MidAmerican Funding's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 8 | | | $ | 8 | |
Additions based on tax positions related to the current year | 16 | | | 4 | |
| | | |
Reductions based on tax positions related to the current year | (11) | | | (3) | |
Reductions for tax positions of prior years | — | | | (1) | |
| | | |
| | | |
| | | |
Ending balance | $ | 13 | | | $ | 8 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 12 |
| | $ | 10 |
|
Additions based on tax positions related to the current year | 4 |
| | 1 |
|
Additions for tax positions of prior years | 47 |
| | 23 |
|
Reductions based on tax positions related to the current year | (4 | ) | | (4 | ) |
Reductions for tax positions of prior years | (48 | ) | | (19 | ) |
Interest and penalties | (1 | ) | | 1 |
|
Ending balance | $ | 10 |
| | $ | 12 |
|
As of December 31, 2018,2021, MidAmerican Funding had unrecognized tax benefits totaling $30$33 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MidAmerican Funding's effective income tax rate.
(10)Employee Benefit Plans
Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements for additional information regarding MidAmerican Funding's pension, supplemental retirement and postretirement benefit plans.
Pension and postretirement costs allocated by MidAmerican Funding to its parent and other affiliates in each of the years ended December 31, were as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Pension costs | $ | 21 | | | $ | 7 | | | $ | 4 | |
Other postretirement costs | 2 | | | (3) | | | (2) | |
(11)Asset Retirement Obligations
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Pension costs | $ | 3 |
| | $ | 4 |
| | $ | 4 |
|
Other postretirement costs | (2 | ) | | (3 | ) | | (1 | ) |
| |
(11) | Asset Retirement Obligations |
Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements.
(12)Fair Value Measurements
Refer to Note 12 of MidAmerican Energy's Notes to Financial Statements.
MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,961 | | | $ | 9,350 | | | $ | 7,450 | | | $ | 9,466 | |
|
| | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 5,621 |
| | $ | 5,943 |
| | $ | 5,282 |
| | $ | 6,006 |
|
(13)Commitments and Contingencies
Refer to Note 13 of MidAmerican Energy's Notes to Financial Statements.
Legal Matters
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
| |
(14) | Components of Accumulated Other Comprehensive Loss, Net |
(14) Revenue from Contracts with Customers
Refer to Note 14 of MidAmerican Energy's Notes to Financial Statements.
(15) Revenue from Contracts with Customers
Refer to Note 15 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had $4$— million, $8 million and $2 million of other revenue from contracts with customers for the year ended December 31, 2018.2021, 2020 and 2019, respectively.
(15)Other Income (Expense) - Other, Net
Other, net, as shown on the Consolidated Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Non-service cost components of postretirement employee benefit plans | $ | 26 | | | $ | 24 | | | $ | 17 | |
Corporate-owned life insurance income | 21 | | | 16 | | | 24 | |
Gains on disposition of assets | — | | | 6 | | | — | |
| | | | | |
| | | | | |
Interest income and other, net | 7 | | | 6 | | | 11 | |
Total | $ | 54 | | | $ | 52 | | | $ | 52 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Non-service cost components of postretirement employee benefit plans | $ | 21 |
| | $ | 18 |
| | $ | 15 |
|
Corporate-owned life insurance income | 6 |
| | 13 |
| | 8 |
|
Gain on redemption of auction rate securities | — |
| | — |
| | 5 |
|
Gains on sales of assets and other investments | 1 |
| | 1 |
| | 3 |
|
Loss on debt tender offer | — |
| | (29 | ) | | — |
|
Interest income and other, net | 3 |
| | 6 |
| | 3 |
|
Total | $ | 31 |
| | $ | 9 |
| | $ | 34 |
|
Refer to Note 8 for information regarding the debt tender offer.
(17)(16)Supplemental Cash Flow Information
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 20182021 and 2017,2020 consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements.wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 20182021 and 20172020 as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 233 | | | $ | 39 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 240 | | | $ | 46 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
Cash and cash equivalents | $ | 1 |
| | $ | 172 |
|
Restricted cash and cash equivalents in other current assets | 56 |
| | 110 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 57 |
| | $ | 282 |
|
The summary of supplemental cash flow information as of and for the years ending December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 296 | | | $ | 302 | | | $ | 245 | |
Income taxes received, net | $ | 751 | | | $ | 715 | | | $ | 456 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accounts payable related to utility plant additions | $ | 257 | | | $ | 227 | | | $ | 337 | |
Distribution of corporate aircraft to parent | $ | — | | | $ | — | | | $ | 8 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Supplemental cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 218 |
| | $ | 218 |
| | $ | 204 |
|
Income taxes received, net | $ | 511 |
| | $ | 472 |
| | $ | 609 |
|
| | | | | |
Supplemental disclosure of non-cash investing transactions: | | | | | |
Accounts payable related to utility plant additions | $ | 371 |
| | $ | 224 |
| | $ | 131 |
|
Transfer of unregulated retail services business to affiliate | $ | — |
| | $ | — |
| | $ | 90 |
|
(17)Related Party Transactions
| |
(18) | Related Party Transactions |
The companies identified as affiliates of MidAmerican Funding are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in servicein-service agreements between MidAmerican Funding and the affiliates.
MidAmerican Funding is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for allocated general costs, such as insurance and building rent, and for employee wages, benefits and costs for corporate functions, such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $44$65 million, $46 million and $35$41 million for 2018, 20172021, 2020 and 2016,2019, respectively. Additionally, in 2018, MidAmerican Funding received $152019, recorded a noncash dividend of $8 million from BHE for the transfer to BHE of corporate aircraft.aircraft owned by MHC.
MidAmerican Funding reimbursed BHE in the amount of $11$72 million, $9$15 million and $6$14 million in 2018, 20172021, 2020 and 2016,2019, respectively, for its share of corporate expenses.
MidAmerican Energy purchases, in the normal course of business at either tariffed or market prices. natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE and coal transportation services from BNSF Railway Company, a wholly-owned subsidiary of Berkshire Hathaway, in the normal course of business at either tariffed or market prices.Hathaway. These purchases totaled $127$132 million, $122$129 million and $135$139 million in 2018, 20172021, 2020 and 2016,2019, respectively. Additionally, in 2020, MidAmerican Energy paid $7 million to BHE Renewables, LLC, a wholly owned subsidiary of BHE, for the purchase of wind turbine components.
MHC has a $300 million revolving credit arrangement carrying interest at the 30-day LIBORLondon Interbank Offered Rate ("LIBOR") rate plus a spread to borrow from BHE. Outstanding balances are unsecured and due on demand. The outstanding balance was $156$189 million at an interest rate of 2.629%0.353% as of December 31, 2018,2021, and $164$177 million at an interest rate of 1.629%0.397% as of December 31, 2017,2020, and is reflected as note payable to affiliate on the Consolidated Balance Sheet.
BHE has a $100 million revolving credit arrangement, carrying interest at the 30-day LIBOR rate plus a spread to borrow from MHC. Outstanding balances are unsecured and due on demand. There were no borrowings outstanding throughout 20182021 and 2017.2020.
MidAmerican Funding had accounts receivable from affiliates of $5$11 million and $9$13 million as of December 31, 20182021 and 2017,2020, respectively, that are included in receivables, netother current assets on the Consolidated Balance Sheets. MidAmerican Funding also had accounts payable to affiliates of $12$17 million and $14$13 million as of December 31, 20182021 and 2017,2020, respectively, that are included in accounts payable on the Consolidated Balance Sheets.
MidAmerican Funding is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, MidAmerican Funding had a payable toreceivable from BHE of $156$80 million as of December 31, 2018,2021, and a receivable frompayable to BHE of $64$14 million as of December 31, 2017.2020. MidAmerican Funding received net cash receiptspayments for federal and state income taxes from BHE totaling $511$751 million, $472$715 million and $609$456 million for the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
MidAmerican Funding recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MidAmerican Funding's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates. MidAmerican Funding adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $20$124 million and $16$146 million as of December 31, 20182021 and 2017,2020, respectively, and similarare included in other assets on the Consolidated Balance Sheets. Similar amounts payable to affiliates totaled $36$63 million and $45$49 million as of December 31, 20182021 and 2017, respectively.2020, respectively, and are included in other long-term liabilities on the Consolidated Balance Sheets. See Note 10 for further information pertaining to pension and postretirement accounting.
The indenture pertaining to MidAmerican Funding's long-term debt restricts MidAmerican Funding from paying a distribution on its equity securities, unless after making such distribution either its debt to total capital ratio does not exceed 0.67:11.0 and its interest coverage ratio is not less than 2.2:11.0 or its senior secured long-term debt rating is at least BBB or its equivalent. MidAmerican Funding may seek a release from this restriction upon delivery to the indenture trustee of written confirmation from the ratings agencies that without this restriction MidAmerican Funding's senior secured long-term debt would be rated at least BBB+.
(18)Segment Information
MidAmerican Funding has identified two2 reportable operating segments: regulated electric and regulated natural gas. The previously reported nonregulated energy segment consisted substantially of MidAmerican Energy's unregulated retail services business, which was transferred to a subsidiary of BHE and is excluded from the information below related to the statements of operations for all periods presented. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the nonregulated subsidiaries of MidAmerican Funding not engaged in the energy business and parent company interest expense. Refer to Note 9 for a discussion of items affecting income tax (benefit) expense for the regulated electric and natural gas operating segments.
The following tables provide information on a reportable segment basis (in millions):
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,529 | | | $ | 2,139 | | | $ | 2,237 | |
Regulated natural gas | 1,003 | | | 573 | | | 660 | |
Other | 15 | | | 16 | | | 30 | |
Total operating revenue | $ | 3,547 | | | $ | 2,728 | | | $ | 2,927 | |
| | | | | |
Depreciation and amortization: | | | | | |
Regulated electric | $ | 861 | | | $ | 667 | | | $ | 593 | |
Regulated natural gas | 53 | | | 49 | | | 46 | |
Total depreciation and amortization | $ | 914 | | | $ | 716 | | | $ | 639 | |
| | | | | |
Operating income: | | | | | |
Regulated electric | $ | 358 | | | $ | 384 | | | $ | 473 | |
Regulated natural gas | 58 | | | 64 | | | 71 | |
Other | — | | | 6 | | | 5 | |
Total operating income | $ | 416 | | | $ | 454 | | | $ | 549 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Interest expense: | | | | | |
Regulated electric | $ | 279 | | | $ | 281 | | | $ | 259 | |
Regulated natural gas | 23 | | | 23 | | | 22 | |
Other | 17 | | | 18 | | | 21 | |
Total interest expense | $ | 319 | | | $ | 322 | | | $ | 302 | |
| | | | | |
Income tax (benefit) expense: | | | | | |
Regulated electric | $ | (677) | | | $ | (584) | | | $ | (384) | |
Regulated natural gas | 3 | | | 14 | | | 12 | |
Other | (6) | | | (4) | | | (5) | |
Total income tax (benefit) expense | $ | (680) | | | $ | (574) | | | $ | (377) | |
| | | | | |
Net income: | | | | | |
Regulated electric | $ | 844 | | | $ | 780 | | | $ | 739 | |
Regulated natural gas | 50 | | | 45 | | | 52 | |
Other | (11) | | | (7) | | | (10) | |
Net income | $ | 883 | | | $ | 818 | | | $ | 781 | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,283 |
| | $ | 2,108 |
| | $ | 1,985 |
|
Regulated natural gas | 754 |
| | 719 |
| | 637 |
|
Other | 16 |
| | 19 |
| | 9 |
|
Total operating revenue | $ | 3,053 |
| | $ | 2,846 |
| | $ | 2,631 |
|
| | | | | |
Depreciation and amortization: | | | | | |
Regulated electric | $ | 565 |
| | $ | 458 |
| | $ | 436 |
|
Regulated natural gas | 44 |
| | 42 |
| | 43 |
|
Total depreciation and amortization | $ | 609 |
| | $ | 500 |
| | $ | 479 |
|
| | | | | |
Operating income: | | | | | |
Regulated electric | $ | 469 |
| | $ | 472 |
| | $ | 486 |
|
Regulated natural gas | 81 |
| | 72 |
| | 64 |
|
Other | — |
| | — |
| | 1 |
|
Total operating income | $ | 550 |
| | $ | 544 |
| | $ | 551 |
|
| | | | | |
Interest expense: | | | | | |
Regulated electric | $ | 208 |
| | $ | 196 |
| | $ | 178 |
|
Regulated natural gas | 19 |
| | 18 |
| | 18 |
|
Other | 20 |
| | 23 |
| | 23 |
|
Total interest expense | $ | 247 |
| | $ | 237 |
| | $ | 219 |
|
| | | | | |
Income tax (benefit) expense: | | | | | |
Regulated electric | $ | (273 | ) | | $ | (212 | ) | | $ | (156 | ) |
Regulated natural gas | 16 |
| | 29 |
| | 22 |
|
Other | (5 | ) | | (19 | ) | | (5 | ) |
Total income tax (benefit) expense | $ | (262 | ) | | $ | (202 | ) | | $ | (139 | ) |
| | | | | |
Net income: | | | | | |
Regulated electric | $ | 628 |
| | $ | 570 |
| | $ | 512 |
|
Regulated natural gas | 54 |
| | 35 |
| | 32 |
|
Other | (13 | ) | | (31 | ) | | (12 | ) |
Net income | $ | 669 |
| | $ | 574 |
| | $ | 532 |
|
| | | | | |
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Capital expenditures: | | | | | |
Regulated electric | $ | 1,806 | | | $ | 1,704 | | | $ | 2,684 | |
Regulated natural gas | 106 | | | 132 | | | 126 | |
Total capital expenditures | $ | 1,912 | | | $ | 1,836 | | | $ | 2,810 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 | | 2019 |
Total assets: | | | | | |
Regulated electric | $ | 22,576 | | | $ | 21,083 | | | $ | 20,284 | |
Regulated natural gas | 1,950 | | | 1,623 | | | 1,547 | |
Other | 5 | | | 5 | | | 9 | |
Total assets | $ | 24,531 | | | $ | 22,711 | | | $ | 21,840 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Capital expenditures: | | | | | |
Regulated electric | $ | 2,223 |
| | $ | 1,686 |
| | $ | 1,564 |
|
Regulated natural gas | 109 |
| | 87 |
| | 72 |
|
Total capital expenditures | $ | 2,332 |
| | $ | 1,773 |
| | $ | 1,636 |
|
|
| | | | | | | | | | | |
| As of December 31, |
| 2018 | | 2017 | | 2016 |
Total assets: | | | | | |
Regulated electric | $ | 17,702 |
| | $ | 16,105 |
| | $ | 15,304 |
|
Regulated natural gas | 1,485 |
| | 1,482 |
| | 1,424 |
|
Other | 15 |
| | 34 |
| | 19 |
|
Total assets | $ | 19,202 |
| | $ | 17,621 |
| | $ | 16,747 |
|
Goodwill by reportable segment as of December 31, 20182021 and 2017,2020, was as follows (in millions):
|
| | | |
Regulated electric | $ | 1,191 |
|
Regulated natural gas | 79 |
|
Total | $ | 1,270 |
|
| | | | | |
(20)Regulated electric | Unaudited Quarterly Operating Results (in millions)$ | 1,191 | |
Regulated natural gas | 79 | |
Total | $ | 1,270 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2018 | | 2018 | | 2018 | | 2018 |
| | | | | | | |
Operating revenue | $ | 747 |
| | $ | 718 |
| | $ | 832 |
| | $ | 756 |
|
Operating income | 79 |
| | 87 |
| | 278 |
| | 106 |
|
Net income (loss) | 103 |
| | 103 |
| | 479 |
| | (16 | ) |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2017 | | 2017 | | 2017 | | 2017 |
| | | | | | | |
Operating revenue | $ | 696 |
| | $ | 659 |
| | $ | 815 |
| | $ | 676 |
|
Operating income | 102 |
| | 131 |
| | 284 |
| | 27 |
|
Net income | 102 |
| | 131 |
| | 383 |
| | (42 | ) |
Quarterly operating results are affected by, among other things, MidAmerican Energy's seasonal retail electricity prices, the timing of recognition of federal renewable electricity production tax credits related to MidAmerican Energy's wind-powered generating facilities and the seasonal impact of weather on electricity and natural gas sales.
Nevada Power Company and its subsidiaries
Consolidated Financial Section
Item 6. Selected Financial Data
Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Nevada Power's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. Nevada Power is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Nevada Power. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Nevada Power.
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Nevada Power's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Nevada Power's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 20182021 was $226$303 million, a decreasean increase of $29$8 million, or 11%3%, compared to 2017,2020, primarily due to $52$92 million of higherlower operations and maintenance expense, mainly due to an accrual for earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and increased political activity expenses, $37 million of lower utility margin and higher depreciation and amortization, primarily due to various regulatory-directedlower net regulatory instructed deferrals and amortizations, established in the Nevada Power 2017 regulatory rate review. These decreases were partially offset bylower earnings sharing and lower plant operations and maintenance expenses, $36 million of lower income tax expense of $84 million, primarily from a lower federal tax rate due to the impactrecognition of the Tax Cutsamortization of excess deferred income taxes following regulatory approval effective January 2021, $10 million of higher interest and Jobs Act (the "2017 Tax Reform") anddividend income, mainly from carrying charges on regulatory balances, $9 million of lower interest expense on long-term debt. Utility margins decreasedand $9 million of higher other, net. These increases are offset by $102 million of lower utility margin, primarily due to lower average retail rates includingfrom the 2020 regulatory rate impacts relatedreview with new rates effective January 2021, lower revenue recognized due to the tax rate reduction rider as a result of 2017 Tax Reformfavorable regulatory decision in 2020 and lower margins from customers purchasing energy from alternative providers and becoming distribution only service customers,an adjustment to regulatory-related revenue deferrals, partially offset by an increase in the average number of customers and higher residential, commercialtransmission revenue, and industrial volumes.$45 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in-service.
Net income for the year ended December 31, 20172020 was $255$295 million, a decreasean increase of $24$31 million, or 9%12%, compared to 2016, which includes $5 million of expense from 2017 Tax Reform. Excluding the impact of the 2017 Tax Reform, adjusted net income was $260 million, a decrease of $19 million compared to 2017, due to expenses related to the Nevada Power regulatory rate review of $28 million, higher depreciation and amortization,2019, primarily due to higher plant placed in-service$97 million of $29 million. The decrease was partially offset by higher utility margins of $11 million, excluding the impact of a decrease in energy efficiency program rate revenue of $22 million (offset in operations and maintenance), and lower interest expense of $9 million on lower deferred charges and lower rates on outstanding debt balances. Utility margins increasedmargin mainly due to higher retail customer usage patternsvolumes, revenue recognized due to a favorable regulatory decision and price impacts from changes in sales mix. Retail customer growth, partially offset by lower utility margins from customers purchasing energy from alternative providers and becomingvolumes, including distribution only service customers.customers, increased 2.0%, primarily due to the favorable impact of weather, largely offset by the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage. The increase in net income is offset by $69 million of higher operations and maintenance expenses primarily due to a higher accrual for earnings sharing of $43 million and higher regulatory-directed debits of $27 million.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada Power's cost of fuel and energy areis generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Nevada Power's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of salesfuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 2,139 | | | $ | 1,998 | | | $ | 141 | | 7 | % | | $ | 1,998 | | | $ | 2,148 | | | $ | (150) | | (7) | % |
Cost of fuel and energy | | 939 | | | 816 | | | 123 | | 15 | | | 816 | | | 943 | | | (127) | | (13) | |
Utility margin | | 1,200 | | | 1,182 | | | 18 | | 2 | | | 1,182 | | | 1,205 | | | (23) | | (2) | |
Operations and maintenance | | 301 | | | 299 | | | 2 | | 1 | | | 299 | | | 324 | | | (25) | | (8) | |
Depreciation and amortization | | 406 | | | 361 | | | 45 | | 12 | | | 361 | | | 357 | | | 4 | | 1 | |
Property and other taxes | | 48 | | | 47 | | | 1 | | 2 | | | 47 | | | 45 | | | 2 | | 4 | |
Operating income | | $ | 445 | | | $ | 475 | | | $ | (30) | | (6) | % | | $ | 475 | | | $ | 479 | | | $ | (4) | | (1) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 2,184 |
| | $ | 2,206 |
| | $ | (22 | ) | (1 | )% | | $ | 2,206 |
| | $ | 2,083 |
| | $ | 123 |
| 6 | % |
Cost of fuel and energy | | 917 |
| | 902 |
| | 15 |
| 2 |
| | 902 |
| | 768 |
| | 134 |
| 17 |
|
Utility margin | | 1,267 |
| | 1,304 |
| | (37 | ) | (3 | ) | | 1,304 |
| | 1,315 |
| | (11 | ) | (1 | ) |
Operations and maintenance | | 443 |
| | 391 |
| | 52 |
| 13 |
| | 391 |
| | 391 |
| | — |
| — |
|
Depreciation and amortization | | 337 |
| | 308 |
| | 29 |
| 9 |
| | 308 |
| | 303 |
| | 5 |
| 2 |
|
Property and other taxes | | 41 |
| | 40 |
| | 1 |
| 3 |
| | 40 |
| | 38 |
| | 2 |
| 5 |
|
Operating income | | $ | 446 |
| | $ | 565 |
| | $ | (119 | ) | (21 | ) | | $ | 565 |
| | $ | 583 |
| | $ | (18 | ) | (3 | ) |
Utility Margin
A comparison of Nevada Power's key operating results related to utility margin is as follows:follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 2,139 | | | $ | 1,998 | | | $ | 141 | | 7 | % | | $ | 1,998 | | | $ | 2,148 | | | $ | (150) | | (7) | % |
Cost of fuel and energy | | 939 | | | 816 | | | 123 | | 15 | | | 816 | | | 943 | | | (127) | | (13) | |
Utility margin | | $ | 1,200 | | | $ | 1,182 | | | $ | 18 | | 2 | % | | $ | 1,182 | | | $ | 1,205 | | | $ | (23) | | (2) | % |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 10,415 | | | 10,477 | | | (62) | | (1) | % | | 10,477 | | | 9,311 | | | 1,166 | | 13 | % |
Commercial | | 4,838 | | | 4,591 | | | 247 | | 5 | | | 4,591 | | | 4,657 | | | (66) | | (1) | |
Industrial | | 5,270 | | | 4,881 | | | 389 | | 8 | | | 4,881 | | | 5,344 | | | (463) | | (9) | |
Other | | 198 | | | 195 | | | 3 | | 2 | | | 195 | | | 193 | | | 2 | | 1 | |
Total fully bundled(1) | | 20,721 | | | 20,144 | | | 577 | | 3 | | | 20,144 | | | 19,505 | | | 639 | | 3 | |
Distribution only service | | 2,646 | | | 2,425 | | | 221 | | 9 | | | 2,425 | | | 2,613 | | | (188) | | (7) | |
Total retail | | 23,367 | | | 22,569 | | | 798 | | 4 | | | 22,569 | | | 22,118 | | | 451 | | 2 | |
Wholesale | | 356 | | | 374 | | | (18) | | (5) | | | 374 | | | 527 | | | (153) | | (29) | |
Total GWhs sold | | 23,723 | | | 22,943 | | | 780 | | 3 | % | | 22,943 | | | 22,645 | | | 298 | | 1 | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 985 | | | 968 | | | 17 | | 2 | % | | 968 | | | 951 | | | 17 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 98.62 | | | $ | 94.83 | | | $ | 3.79 | | 4 | % | | $ | 94.83 | | | $ | 105.88 | | | $ | (11.05) | | (10) | % |
Wholesale | | $ | 60.69 | | | $ | 42.83 | | | $ | 17.86 | | 42 | % | | $ | 42.83 | | | $ | 35.87 | | | $ | 6.96 | | 19 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 1,613 | | | 1,753 | | | (140) | | (8) | % | | 1,753 | | | 1,875 | | | (122) | | (7) | % |
Cooling degree days | | 4,109 | | | 4,236 | | | (127) | | (3) | % | | 4,236 | | | 3,648 | | | 588 | | 16 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 13,655 | | | 13,545 | | | 110 | | 1 | % | | 13,545 | | | 13,161 | | | 384 | | 3 | % |
Coal | | — | | | — | | | — | | — | | | — | | | 1,059 | | | (1,059) | | (100) | |
Renewables | | 65 | | | 66 | | | (1) | | (2) | | | 66 | | | 61 | | | 5 | | 8 | |
Total energy generated | | 13,720 | | | 13,611 | | | 109 | | 1 | | | 13,611 | | | 14,281 | | | (670) | | (5) | |
Energy purchased | | 7,778 | | | 7,044 | | | 734 | | 10 | | | 7,044 | | | 6,167 | | | 877 | | 14 | |
Total | | 21,498 | | | 20,655 | | | 843 | | 4 | % | | 20,655 | | | 20,448 | | | 207 | | 1 | % |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(4): | | | | | | | | | | | | | | |
Energy generated | | $ | 24.41 | | | $ | 16.58 | | | $ | 7.83 | | 47 | % | | $ | 16.58 | | | $ | 26.95 | | | $ | (10.37) | | (38) | % |
Energy purchased | | $ | 77.64 | | | $ | 83.74 | | | $ | (6.10) | | (7) | % | | $ | 83.74 | | | $ | 90.50 | | | $ | (6.75) | | (7) | % |
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes -, - and 153 GWhs of coal and 1,389, 1,614 and 1,756 GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2021, 2020 and 2019, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 2,184 |
| | $ | 2,206 |
| | $ | (22 | ) | (1 | )% | | $ | 2,206 |
| | $ | 2,083 |
| | $ | 123 |
| 6 | % |
Cost of fuel and energy | | 917 |
| | 902 |
| | 15 |
| 2 |
| | 902 |
| | 768 |
| | 134 |
| 17 |
|
Utility margin | | $ | 1,267 |
| | $ | 1,304 |
| | $ | (37 | ) | (3 | ) | | $ | 1,304 |
| | $ | 1,315 |
| | $ | (11 | ) | (1 | ) |
| | | | | | | | | | | | | | |
GWhs sold: | | | | | | | | | | | | | | |
Residential | | 9,970 |
| | 9,501 |
| | 469 |
| 5 | % | | 9,501 |
| | 9,394 |
| | 107 |
| 1 | % |
Commercial | | 4,778 |
| | 4,656 |
| | 122 |
| 3 |
| | 4,656 |
| | 4,663 |
| | (7 | ) | — |
|
Industrial | | 5,534 |
| | 6,201 |
| | (667 | ) | (11 | ) | | 6,201 |
| | 7,313 |
| | (1,112 | ) | (15 | ) |
Other | | 214 |
| | 212 |
| | 2 |
| 1 |
| | 212 |
| | 212 |
| | — |
| — |
|
Total fully bundled(1) | | 20,496 |
| | 20,570 |
| | (74 | ) | — |
| | 20,570 |
| | 21,582 |
| | (1,012 | ) | (5 | ) |
Distribution only service | | 2,521 |
| | 1,830 |
| | 691 |
| 38 |
| | 1,830 |
| | 662 |
| | 1,168 |
| * |
|
Total retail | | 23,017 |
| | 22,400 |
| | 617 |
| 3 |
| | 22,400 |
| | 22,244 |
| | 156 |
| 1 |
|
Wholesale | | 274 |
| | 314 |
| | (40 | ) | (13 | ) | | 314 |
| | 258 |
| | 56 |
| 22 |
|
Total GWhs sold | | 23,291 |
| | 22,714 |
| | 577 |
| 3 |
| | 22,714 |
| | 22,502 |
| | 212 |
| 1 |
|
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands): | | | | | | | | | | | | | | |
Residential | | 825 |
| | 810 |
| | 15 |
| 2 | % | | 810 |
| | 796 |
| | 14 |
| 2 | % |
Commercial | | 108 |
| | 106 |
| | 2 |
| 2 |
| | 106 |
| | 105 |
| | 1 |
| 1 |
|
Industrial | | 2 |
| | 2 |
| | — |
| — |
| | 2 |
| | 2 |
| | — |
| — |
|
Total | | 935 |
| | 918 |
| | 17 |
| 2 |
| | 918 |
| | 903 |
| | 15 |
| 2 |
|
| | | | | | | | | | | | | | |
Average per MWh: | | | | | | | | | | | | | | |
Revenue - fully bundled(1) | | $ | 102.82 |
| | $ | 104.57 |
| | $ | (1.75 | ) | (2 | )% | | $ | 104.57 |
| | $ | 94.27 |
| | $ | 10.30 |
| 11 | % |
Total cost of energy(2)(3) | | $ | 42.17 |
| | $ | 41.84 |
| | $ | 0.33 |
| 1 | % | | $ | 41.84 |
| | $ | 34.00 |
| | $ | 7.84 |
| 23 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 1,527 |
| | 1,265 |
| | 262 |
| 21 | % | | 1,265 |
| | 1,508 |
| | (243 | ) | (16 | )% |
Cooling degree days | | 4,255 |
| | 4,044 |
| | 211 |
| 5 | % | | 4,044 |
| | 4,002 |
| | 42 |
| 1 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(3)(4): | | | | | | | | | | | | | | |
Natural gas | | 13,848 |
| | 13,172 |
| | 676 |
| 5 | % | | 13,172 |
| | 14,577 |
| | (1,405 | ) | (10 | )% |
Coal | | 1,231 |
| | 1,449 |
| | (218 | ) | (15 | ) | | 1,449 |
| | 1,480 |
| | (31 | ) | (2 | ) |
Renewables | | 69 |
| | 73 |
| | (4 | ) | (5 | ) | | 73 |
| | 61 |
| | 12 |
| 20 |
|
Total energy generated | | 15,148 |
| | 14,694 |
| | 454 |
| 3 |
| | 14,694 |
| | 16,118 |
| | (1,424 | ) | (9 | ) |
Energy purchased | | 6,587 |
| | 6,858 |
| | (271 | ) | (4 | ) | | 6,858 |
| | 6,462 |
| | 396 |
| 6 |
|
Total | | 21,735 |
| | 21,552 |
| | 183 |
| 1 |
| | 21,552 |
| | 22,580 |
| | (1,028 | ) | (5 | ) |
| |
(1) | Fully bundled includes sales to customers for combined energy, transmission and distribution services. |
| |
(2) | The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs. |
| |
(3) | The average total cost of energy per MWh and sources of energy excludes 153, 296 and 194 GWhs of coal and 1,483, 2,373 and 2,215 GWhs of gas generated energy that is purchased at cost by related parties for the years ended December 31, 2018, 2017 and 2016, respectively. |
| |
(4) | GWh amounts are net of energy used by the related generating facilities. |
Year Ended December 31, 20182021 Compared to Year Ended December 31, 20172020
Utility margin decreased $37 increased $18 million, or 2%, for 20182021 compared to 20172020 primarily due to:
$51•the $120 million one-time bill credit returned to customers in 2020 as a result of the Nevada Power regulatory rate review stipulation ("$120 million bill credit") (offset in operations and maintenance expense and income tax expense) and
•$5 million of higher transmission revenue.
The increase in utility margin was offset by:
•$66 million of lower retail electric utility margin primarily due to lower retail rates due to the tax2020 regulatory rate reduction rider asreview with new rates effective January 2021, offset by higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 3.5% primarily due to an increase in the average number of customers and favorable changes in customer usage patterns, offset by the unfavorable impact of weather;
•$21 million of lower revenue recognized due to a result of 2017 Tax Reform;favorable regulatory decision in 2020;
•$3010 million due to lower retail rates asenergy efficiency program costs (offset in operations and maintenance expense);
•$6 million due to an adjustment to regulatory-related revenue deferrals; and
•$4 million due to a resultregulatory amortization of an impact fee that ended December 2020.
Operations and maintenance increased $2 million, or 1%, for 2021 compared to 2020 primarily due to regulatory liability amortization in 2020 to satisfy a portion of the 2017$120 million bill credit of $94 million (offset in operating revenue), partially offset by lower net regulatory instructed deferrals and amortizations of $46 million, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective February 2018;January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation, lower earnings sharing, lower energy efficiency program costs (offset in operating revenue) and lower plant operations and maintenance expenses.
$20
Depreciation and amortization increased $45 million, or 12%, for 2021 compared to 2020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in-service.
Interest expense decreased $9 million, or 6%, for 2021 compared to 2020 primarily due to lower commercialcarrying charges on regulatory balances of $6 million and industrial retaillower interest expense on long-term debt.
Interest and dividend income increased $10 million for 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $9 million, for 2021 compared to 2020 primarily due to lower pension expense of $6 million and higher cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased $10 million, or 21%, for 2021 compared to 2020. The effective tax rate was 11% in 2021 and 14% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, partially offset by the one-time recognition in 2020 of amortization of excess deferred income taxes to satisfy a portion of the $120 million bill credit (offset in operating revenue).
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Utility margin decreased $23 million for 2020 compared to 2019 due to:
•the $120 million bill credit (offset in operations and maintenance expense and income tax expense) and
•$5 million of higher revenue from customers purchasing energy from alternative providers and becoming distribution-onlyreductions related to customer service customers.agreements.
The decrease in utility margin was partially offset by:
•$2045 million in higher residential customer volumes from the favorable impact of weather;
•$21 million of revenue recognized due to a favorable regulatory decision;
•$16 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution-only service customers, increased 2.0% primarily fromdue to the favorable impacts of weather, offset by the impacts of weather;
$20 millionCOVID-19, which resulted in higherlower industrial, commercial and industrial volumes;
$11 million in higher other revenue primarily from impact fees and revenue relating to customers becoming distribution-only service customers;customer usage and higher residential customer usage;
•$98 million due to residential customer growth; and
$4 million in higher energy efficiency program rate revenue, which is offsetcosts (offset in operations and maintenance expense.expense);
•$7 million of higher transmission and wholesale revenue; and
•$5 million of customer growth mainly from residential customers.
Operations and maintenance increased $52decreased $25 million, or 13%8%, for 20182020 compared to 20172019 primarily due to anhigher regulatory liability amortization to satisfy a portion of the $120 million bill credit of $94 million (offset in operating revenue) and lower plant operation and maintenance costs, partially offset by a higher accrual for earnings sharing established in 2018 as partof $43 million, higher regulatory-directed debits of $27 million, relating to the deferral of the non-labor cost savings from the Navajo generating station retirement in 2019, the deferral of costs for the ON Line lease to be returned to customers due to the regulatory-directed reallocation of costs between Nevada Power 2017 regulatory rate review and increased political activity expenses, partially offset by disallowancesSierra Pacific (offset in 2017 resulting from regulatory rate reviews.depreciation and amortization and other income (expense)) and costs recognized for the $120 million bill credit, and higher energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $29$4 million, or 9%1%, for 20182020 compared to 20172019 primarily due to various regulatory-directed amortizations and increasedhigher plant placed in-service, offset by lower depreciation expense as a resulton the ON Line lease due to the regulatory-directed reallocation of thecosts between Nevada Power 2017 regulatory rate review.and Sierra Pacific (offset in operations and maintenance).
Other income (expense) is favorable $6Property and other taxes increased $2 million, or 4%, for 20182020 compared to 20172019 primarily due to a decrease in available abatements and franchise tax audit assessments.
Other income (expense) is favorable $9 million, or 6%, for 2020 compared to 2019 primarily due to lower interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense), lower pension costs and lower interest expense on long-term debt partiallydue to lower interest rates, offset by an unfavorable clarification order from the 2017 regulatory rate reviewlower other income due to record carrying charges on impact fees received from customers that elected to become distribution only service customersa licensing agreement with a third party in 2019 and losses on investments.lower cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased $84$26 million, or 54%36%, for 20182020 compared to 2017.2019. The effective tax rate was 24%14% in 20182020 and 38%22% in 2017. The decrease in the effective tax rate is primarily due to 2017 Tax Reform, which reduced the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, partially offset by an increase in nondeductible expenses.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Utility margin2019 and decreased $11 million for 2017 compared to 2016 due to:
$32 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution-only service customers; and
$22 million in lower energy efficiency program rate revenue, which is offset in operations and maintenance.
The decrease in utility margin was partially offset by:
$21 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;
$9 million from customer usage patterns;
$7 million due to customer growth; and
$6 million in higher transmission revenue primarily due to customers becoming distribution-only service customers.
Depreciation and amortization increased $5 million, or 2%, for 2017 compared to 2016 primarily due to higher plant placed in-service.
Property and other taxes increased$2 million, or 5%, for 2017 compared to 2016 due to a reduction in property tax abatements.
Other income (expense) is favorable $4 million, or 3%, for 2017 compared to 2016 due to lower interest expense on deferred charges and the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in 2016, partially offset by lower allowance for funds used during construction and expenses related to the regulatory rate review.
Income tax expense increased $10 million, or 7%, for 2017 compared to 2016. The effective tax rate was 38% in 2017 and 34% in 2016. The increase in the effective tax rate is primarily due to the effectsone-time recognition of 2017 Tax Reform andamortization of excess deferred income taxes to satisfy a portion of the qualified production activities deduction$120 million bill credit (offset in 2016.operating revenue).
Liquidity and Capital Resources
As of December 31, 2018,2021, Nevada Power's total net liquidity was $511$253 million as follows (in millions):
|
| | | | |
Cash and cash equivalents | | $ | 111 |
|
Credit facilities(1) | | 400 |
|
Total net liquidity | | $ | 511 |
|
Credit facilities: | | |
Maturity dates | | 2021 |
|
| | | | | | | | |
(1)Cash and cash equivalents | | $ | 33 | |
| | |
Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10Credit facilities(1)
| | 400 | |
Less -K for further discussion regarding Nevada Power's | | |
Short-term debt | | (180) | |
| | |
Net credit facility.facilities | | 220 | |
| | |
Total net liquidity | | $ | 253 | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Nevada Power's credit facility.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 20182021 and 20172020 were $619$505 million and $665$467 million, respectively. The change was primarily due to impact fees received in 2017, higher contributions tocollections from customers, timing of payments for operating costs, increased collections of customer advances and lower inventory purchases, partially offset by the pension plantiming of payments for fuel and energy costs and higher payments for operating costs, partially offset by increased collections from customers due to higher deferred energy rates.income taxes.
Net cash flows from operating activities for the years ended December 31, 20172020 and 20162019 were $665$467 million and $771$701 million, respectively. The change was primarily due to lower collections from customers, mainly due to the $120 million bill credit, higher intercompany tax payments for fuel and higher impact fees receivedenergy costs, the timing of payments for operating costs, lower proceeds from a licensing agreement with a third party in 2016,2019 and decreased collections of customer advances, partially offset by a 2016 contribution to the pension plan.lower payments for income taxes and lower interest payments for long-term debt.
The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 20182021 and 20172020 were $(297)$(447) million and $(343)$(429) million, respectively. The change was primarily due to the acquisition of the remaining 25% in the Silverhawk generating station in 2017, partially offset by increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 20172020 and 20162019 were $(343)$(429) million and $(335)$(407) million, respectively. The change was primarily due to the acquisition of the remaining 25% ownership in the Silverhawk generating station,increased capital expenditures, partially offset by decreasedhigher proceeds from sale of assets primarily related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the years ended December 31, 20182021 and 20172020 were $(267)$(49) million and $(546)$(27) million, respectively. The change was primarily due to greaterlower proceeds from the issuance of long-term debt and higher dividends paid to NV Energy, Inc. in 2017,, partially offset by higherlower repayments of long-term debt and higher net proceeds from short-term debt.
Net cash flows from financing activities for the years ended December 31, 20172020 and 20162019 were $(546)$(27) million and $(693)$(390) million, respectively. The change was primarily due to lower repaymentsgreater proceeds from the issuance of long‑termlong-term debt and proceeds from issuance of long‑term debt, partially offset by higherlower dividends paid to NV Energy, Inc. in 2017., partially offset by higher repayments of long-term debt.
Ability to Issue Debt
Nevada Power currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities through October 15, 2022. Additionally, Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2018,2021, Nevada Power has financing authority from the PUCN consisting of the ability to: (1)to issue long-term and short-term debt securities so long as the total amount of up to $1.3 billion; (2) refinancing authority up to $656debt outstanding (excluding borrowings under Nevada Power's $400 million secured credit facility) does not exceed $3.2 billion as measured at the end of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion.each calendar quarter. Nevada Power's revolving credit facility contains a financial maintenance covenant which Nevada Power was in compliance with as of December 31, 2018.2021. In addition, certain financing agreements contain covenants which are currently suspended as Nevada Power's senior secured debt is rated investment grade. However, if Nevada Power's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Nevada Power would be subject to limitations under these covenants.
In January 2022, the PUCN approved Nevada Power's request to increase its financing authority for debt securities to not exceed $3.8 billion as measured at the end of each calendar quarter. Additionally, the PUCN authorized Nevada Power to issue common and preferred stock so long as the total amounts outstanding do not exceed $4.1 billion and $800 million, respectively, at the end of each calendar quarter.
Ability to Issue General and Refunding Mortgage Securities
To the extent Nevada Power has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Nevada Power's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Nevada Power's indenture.
Nevada Power's indenture creates a lien on substantially all of Nevada Power's properties in Nevada. As of December 31, 2018, $8.52021, $9.4 billion of Nevada Power's assets were pledged. Nevada Power had the capacity to issue $3.2$3.7 billion of additional general and refunding mortgage securities as of December 31, 20182021, determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Nevada Power also has the ability to release property from the lien of Nevada Power's indenture on the basis of net property additions, cash or retired bonds. To the extent Nevada Power releases property from the lien of Nevada Power's indenture, it will reduce the amount of securities issuable under the indenture.
Long-Term Debt
In April 2018,January 2022, Nevada Power issued $575entered into a $300 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020.secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power used a portionborrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the net proceeds to repay all of Nevada Power's $325 million 6.50% General and Refunding Mortgage Notes, Series O, maturing in May 2018. In August 2018,remaining unused commitment through June 2022. Nevada Power used the remaining net proceeds together with available cash and $45m fromto repay amounts outstanding under its existing secured credit facility to repay all of Nevada Power's $500 million 6.50% General and Refunding Mortgage Notes, Series S, maturing in August 2018.for general corporate purposes.
In January 2019, Nevada Power issued $500 million of its 3.70% General and Refunding Mortgage Notes, Series CC, due May 2029.
Future Uses of Cash
Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including Nevada Power's credit ratings, investors' judgment of risk associated with Nevada Power and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Electric distribution | $ | 209 | | | $ | 232 | | | $ | 184 | | | $ | 193 | | | $ | 184 | | | $ | 181 | |
Electric transmission | 24 | | | 35 | | | 57 | | | 169 | | | 206 | | | 432 | |
Solar generation | — | | | — | | | 8 | | | 95 | | | 568 | | | 602 | |
Other | 171 | | | 188 | | | 200 | | | 576 | | | 276 | | | 163 | |
Total | $ | 404 | | | $ | 455 | | | $ | 449 | | | $ | 1,033 | | | $ | 1,234 | | | $ | 1,378 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecasted |
| 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| | | | | | | | | | | |
Generation development | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Distribution | 144 |
| | 110 |
| | 137 |
| | 182 |
| | 318 |
| | 130 |
|
Transmission system investment | 30 |
| | 9 |
| | 9 |
| | 27 |
| | 4 |
| | 6 |
|
Other | 160 |
| | 151 |
| | 150 |
| | 165 |
| | 100 |
| | 150 |
|
Total | $ | 335 |
| | $ | 270 |
| | $ | 296 |
| | $ | 374 |
| | $ | 422 |
| | $ | 286 |
|
Nevada Power received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its IRP filings in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include investments thatthe following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to operating projects thatthe Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission distribution, generation and other infrastructure needed to serve existing and expected demand.
•Solar generation includes growth projects consisting of three solar photovoltaic facilities. The first project is a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The final project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. The facilities located in Humboldt County will be jointly owned and operated by Nevada Power and Sierra Pacific.
Contractual Obligations•Other includes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
Nevada Power has contractual cash obligationsrequirements that may affect its consolidated financial condition. The following table summarizes Nevada Power's material contractual cash obligations as of December 31, 2018 (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Periods |
| | 2019 | | 2020 - 2021 | | 2022 - 2023 | | 2024 and Thereafter | | Total |
| | | | | | | | | | |
Long-term debt | | $ | 500 |
| | $ | 575 |
| | $ | — |
| | $ | 1,309 |
| | $ | 2,384 |
|
Interest payments on long-term debt(1) | | 110 |
| | 162 |
| | 154 |
| | 1,118 |
| | 1,544 |
|
Capital leases, including interest(2),(3) | | 15 |
| | 32 |
| | 22 |
| | 24 |
| | 93 |
|
ON Line financial lease, including interest(2) | | 44 |
| | 88 |
| | 88 |
| | 685 |
| | 905 |
|
Fuel and capacity contract commitments(1) | | 612 |
| | 838 |
| | 769 |
| | 4,925 |
| | 7,144 |
|
Fuel and capacity contract commitments (not commercially operable)(1) | | — |
| | 7 |
| | 80 |
| | 982 |
| | 1,069 |
|
Operating leases and easements(1) | | 10 |
| | 14 |
| | 15 |
| | 59 |
| | 98 |
|
Asset retirement obligations | | 13 |
| | 14 |
| | 20 |
| | 46 |
| | 93 |
|
Maintenance, service and other contracts(1) | | 46 |
| | 85 |
| | 60 |
| | 26 |
| | 217 |
|
Total contractual cash obligations | | $ | 1,350 |
| | $ | 1,815 |
| | $ | 1,208 |
| | $ | 9,174 |
| | $ | 13,547 |
|
| |
(1) | Not reflected on the Consolidated Balance Sheets. |
| |
(2) | Interest is not reflected on the Consolidated Balance Sheets. |
| |
(3) | Includes fuel and capacity contracts designated as a capital lease. |
Nevada Power has other types of commitmentscondition that arise primarily from unused lines of credit, letters of credit or relatelong- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (Liquidity(refer to Liquidity and Capital Resources included within this Item 77) and AROs (refer to Note 6), uncertain tax positions (Note 9) and asset retirement obligations (Note 11), which have not been included in the above table because the amount and timing of the cash payments are not certain.. Refer where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Nevada Power has cash requirements relating to interest payments of $1.8 billion on long-term debt, including $115 million due in 2022.
Regulatory Matters
Nevada Power is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussioninformation regarding Nevada Power's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Nevada Power is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Nevada Power's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Nevada Power has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Nevada Power's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2018,2021, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2018,2021, Nevada Power would have been required to post $10$113 million of additional collateral. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where Nevada Power operates has not had a significant impact on Nevada Power's consolidated financial results. Nevada Power operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Nevada Power is allowed to include prudent costs in its rates, including the impact of inflation after Nevada Power experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Nevada Power attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Nevada Power, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Nevada Power's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Nevada Power's Summary of Significant Accounting Policies included in Nevada Power's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss).AOCI. Total regulatory assets were $0.9$1 billion and total regulatory liabilities were $1.2$1.1 billion as of December 31, 2018.2021. Refer to Nevada Power's Note 56 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2018,2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Nevada Power would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Nevada Power's results of operations.
Income Taxes
In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement.
Although the ultimate resolution of Nevada Power's federal, state and local income tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Nevada Power's consolidated financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations. Refer to Nevada Power's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's income taxes.
It is probable that Nevada Power is probable towill pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property‑property related basis differences and other various differences on to its customers. As of December 31, 2018,2021, these amounts were recognized as a net regulatory liability of $677$603 million and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $106$107 million as of December 31, 2018.2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Nevada Power's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Nevada Power's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Nevada Power transacts. The following discussion addresses the significant market risks associated with Nevada Power's business activities. Nevada Power has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's contracts accounted for as derivatives.
Commodity Price Risk
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity and natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Nevada Power's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Nevada Power's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worstworse case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | (113) | | | $ | (93) | | | $ | (133) | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | 15 | | | $ | 19 | | | $ | 11 | |
|
| | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2018: | | | | | |
Commodity derivative contracts | $ | 3 |
| | $ | 7 |
| | $ | (1 | ) |
| | | | | |
As of December 31, 2017: | | | | | |
Commodity derivative contracts | $ | (3 | ) | | $ | (3 | ) | | $ | (3 | ) |
Nevada Power's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose Nevada Power to earnings volatility. As of December 31, 2018,2021 and 2020, a net regulatory asset of $113 million and a net regulatory liability of $3$15 million, was recorded related to the net derivative asset of $3 million. As of December 31, 2017, a net regulatory asset of $3 millionrespectively, was recorded related to the net derivative liability of $3 million.$113 million and net derivative asset of $15 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Nevada Power is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Nevada Power's fixed-rate long-term debt does not expose Nevada Power to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Nevada Power were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Nevada Power's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 67 and 78 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Nevada Power's short- and long-term debt.
As of December 31, 20182021 and 2017,2020, Nevada Power had no short-short-term variable-rate obligations totaling $180 million and long-term variable-rate obligations$— million, respectively, that expose Nevada Power to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Nevada Power's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2018,2021, Nevada Power's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
Item 8. Financial Statements and Supplementary Data
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| | | |
| | | |
| | | |
| | | |
Consolidated Balance Sheets | | | |
| | | |
Consolidated Statements of Operations | | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries ("Nevada Power") as of December 31, 20182021 and 2017,2020, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2018,2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Nevada Power as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Nevada Power's management. Our responsibility is to express an opinion on Nevada Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Nevada Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Nevada Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Nevada Power is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Nevada Power operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense, and income tax expense.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Nevada Power an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Nevada Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Nevada Power's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Nevada Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected Nevada Power's filings with the Commissions and the filings with the Commissions by intervenors that may impact Nevada Power's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 22, 201925, 2022
We have served as Nevada Power's auditor since 1987.
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 33 | | | $ | 25 | |
Trade receivables, net | 227 | | | 234 | |
Inventories | 64 | | | 69 | |
Derivative contracts | 4 | | | 26 | |
Regulatory assets | 291 | | | 48 | |
| | | |
Prepayments | 33 | | | 38 | |
Other current assets | 49 | | | 26 | |
Total current assets | 701 | | | 466 | |
| | | |
Property, plant and equipment, net | 6,891 | | | 6,701 | |
Finance lease right of use assets, net | 326 | | | 351 | |
Regulatory assets | 728 | | | 746 | |
Other assets | 106 | | | 72 | |
| | | |
Total assets | $ | 8,752 | | | $ | 8,336 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 242 | | | $ | 181 | |
Accrued interest | 32 | | | 32 | |
Accrued property, income and other taxes | 29 | | | 25 | |
Short-term debt | 180 | | | — | |
| | | |
Current portion of finance lease obligations | 26 | | | 27 | |
Regulatory liabilities | 49 | | | 50 | |
Customer deposits | 44 | | | 47 | |
Asset retirement obligation | 19 | | | 25 | |
Derivative contracts | 55 | | | 4 | |
Other current liabilities | 17 | | | 18 | |
Total current liabilities | 693 | | | 409 | |
| | | |
Long-term debt | 2,499 | | | 2,496 | |
Finance lease obligations | 310 | | | 334 | |
Regulatory liabilities | 1,100 | | | 1,163 | |
Deferred income taxes | 782 | | | 738 | |
Other long-term liabilities | 338 | | | 257 | |
Total liabilities | 5,722 | | | 5,397 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding | — | | | — | |
Additional paid-in capital | 2,308 | | | 2,308 | |
Retained earnings | 724 | | | 634 | |
Accumulated other comprehensive loss, net | (2) | | | (3) | |
Total shareholder's equity | 3,030 | | | 2,939 | |
| | | |
Total liabilities and shareholder's equity | $ | 8,752 | | | $ | 8,336 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 111 |
| | $ | 57 |
|
Accounts receivable, net | 240 |
| | 238 |
|
Inventories | 61 |
| | 59 |
|
Regulatory assets | 39 |
| | 28 |
|
Other current assets | 68 |
| | 44 |
|
Total current assets | 519 |
| | 426 |
|
| | | |
Property, plant and equipment, net | 6,868 |
| | 6,877 |
|
Regulatory assets | 878 |
| | 941 |
|
Other assets | 37 |
| | 35 |
|
| | | |
Total assets | $ | 8,302 |
| | $ | 8,279 |
|
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 187 |
| | $ | 156 |
|
Accrued interest | 38 |
| | 50 |
|
Accrued property, income and other taxes | 30 |
| | 63 |
|
Regulatory liabilities | 49 |
| | 91 |
|
Current portion of long-term debt and financial and capital lease obligations | 520 |
| | 842 |
|
Customer deposits | 67 |
| | 73 |
|
Other current liabilities | 29 |
| | 16 |
|
Total current liabilities | 920 |
| | 1,291 |
|
| | | |
Long-term debt and financial and capital lease obligations | 2,296 |
| | 2,233 |
|
Regulatory liabilities | 1,137 |
| | 1,030 |
|
Deferred income taxes | 749 |
| | 767 |
|
Other long-term liabilities | 296 |
| | 280 |
|
Total liabilities | 5,398 |
| | 5,601 |
|
| | | |
Commitments and contingencies (Note 12) | | | |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding | — |
| | — |
|
Other paid-in capital | 2,308 |
| | 2,308 |
|
Retained earnings | 600 |
| | 374 |
|
Accumulated other comprehensive loss, net | (4 | ) | | (4 | ) |
Total shareholder's equity | 2,904 |
| | 2,678 |
|
| | | |
Total liabilities and shareholder's equity | $ | 8,302 |
| | $ | 8,279 |
|
| | | |
The accompanying notes are an integral part of the consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue | $ | 2,139 | | | $ | 1,998 | | | $ | 2,148 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 939 | | | 816 | | | 943 | |
Operations and maintenance | 301 | | | 299 | | | 324 | |
Depreciation and amortization | 406 | | | 361 | | | 357 | |
Property and other taxes | 48 | | | 47 | | | 45 | |
| | | | | |
Total operating expenses | 1,694 | | | 1,523 | | | 1,669 | |
| | | | | |
Operating income | 445 | | | 475 | | | 479 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (153) | | | (162) | | | (171) | |
Allowance for borrowed funds | 3 | | | 3 | | | 3 | |
Allowance for equity funds | 7 | | | 7 | | | 5 | |
Interest and dividend income | 20 | | | 10 | | | 13 | |
Other, net | 18 | | | 9 | | | 8 | |
Total other income (expense) | (105) | | | (133) | | | (142) | |
| | | | | |
Income before income tax expense | 340 | | | 342 | | | 337 | |
Income tax expense | 37 | | | 47 | | | 73 | |
Net income | $ | 303 | | | $ | 295 | | | $ | 264 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Operating revenue | $ | 2,184 |
| | $ | 2,206 |
| | $ | 2,083 |
|
| | | | | |
Operating costs and expenses: | | | | | |
Cost of fuel, energy and capacity | 917 |
| | 902 |
| | 768 |
|
Operations and maintenance | 443 |
| | 391 |
| | 391 |
|
Depreciation and amortization | 337 |
| | 308 |
| | 303 |
|
Property and other taxes | 41 |
| | 40 |
| | 38 |
|
Total operating costs and expenses | 1,738 |
| | 1,641 |
| | 1,500 |
|
| | | | | |
Operating income | 446 |
| | 565 |
| | 583 |
|
| | | | | |
Other income (expense): | | | | | |
Interest expense | (170 | ) | | (179 | ) | | (185 | ) |
Allowance for borrowed funds | 2 |
| | 1 |
| | 4 |
|
Allowance for equity funds | 3 |
| | 1 |
| | 2 |
|
Other, net | 17 |
| | 23 |
| | 21 |
|
Total other income (expense) | (148 | ) | | (154 | ) | | (158 | ) |
| | | | | |
Income before income tax expense | 298 |
| | 411 |
| | 425 |
|
Income tax expense | 72 |
| | 156 |
| | 146 |
|
Net income | $ | 226 |
| | $ | 255 |
| | $ | 279 |
|
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Other | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2018 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 600 | | | $ | (4) | | | $ | 2,904 | |
Net income | | — | | | — | | | — | | | 264 | | | — | | | 264 | |
Dividends declared | | — | | | — | | | — | | | (371) | | | — | | | (371) | |
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 | | | — | | | 2,308 | | | 493 | | | (4) | | | 2,797 | |
Net income | | — | | | — | | | — | | | 295 | | | — | | | 295 | |
Dividends declared | | — | | | — | | | — | | | (155) | | | — | | | (155) | |
Other equity transactions | | — | | | — | | | — | | | 1 | | | 1 | | | 2 | |
Balance, December 31, 2020 | | 1,000 | | | — | | | 2,308 | | | 634 | | | (3) | | | 2,939 | |
Net income | | — | | | — | | | — | | | 303 | | | — | | | 303 | |
Dividends declared | | — | | | — | | | — | | | (213) | | | — | | | (213) | |
Other equity transactions | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Other | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2015 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 858 |
| | $ | (3 | ) | | $ | 3,163 |
|
Net income | | — |
| | — |
| | — |
| | 279 |
| | — |
| | 279 |
|
Dividends declared | | — |
| | — |
| | — |
| | (469 | ) | | — |
| | (469 | ) |
Other equity transactions | | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Balance, December 31, 2016 | | 1,000 |
| | — |
| | 2,308 |
| | 667 |
| | (3 | ) | | 2,972 |
|
Net income | | — |
| | — |
| | — |
| | 255 |
| | — |
| | 255 |
|
Dividends declared | | — |
| | — |
| | — |
| | (548 | ) | | — |
| | (548 | ) |
Other equity transactions | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
Balance, December 31, 2017 | | 1,000 |
| | — |
| | 2,308 |
| | 374 |
| | (4 | ) | | 2,678 |
|
Net income | | — |
| | — |
| | — |
| | 226 |
| | — |
| | 226 |
|
Balance, December 31, 2018 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 600 |
| | $ | (4 | ) | | $ | 2,904 |
|
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 303 | | | $ | 295 | | | $ | 264 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 406 | | | 361 | | | 357 | |
Allowance for equity funds | (7) | | | (7) | | | (5) | |
Changes in regulatory assets and liabilities | (19) | | | (42) | | | 27 | |
Deferred income taxes and amortization of investment tax credits | — | | | (10) | | | (32) | |
Deferred energy | (245) | | | (44) | | | 51 | |
Amortization of deferred energy | 11 | | | (41) | | | 43 | |
Other, net | — | | | 2 | | | (5) | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | 6 | | | 45 | | | 19 | |
Inventories | 5 | | | (7) | | | 1 | |
Accrued property, income and other taxes | (18) | | | 5 | | | (13) | |
Accounts payable and other liabilities | 63 | | | (90) | | | (6) | |
Net cash flows from operating activities | 505 | | | 467 | | | 701 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (449) | | | (455) | | | (409) | |
| | | | | |
Proceeds from sale of assets | — | | | 26 | | | 2 | |
Other, net | 2 | | | — | | | — | |
Net cash flows from investing activities | (447) | | | (429) | | | (407) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | 718 | | | 495 | |
Repayments of long-term debt | — | | | (575) | | | (500) | |
Net proceeds from short-term debt | 180 | | | — | | | — | |
Dividends paid | (213) | | | (155) | | | (371) | |
Other, net | (16) | | | (15) | | | (14) | |
Net cash flows from financing activities | (49) | | | (27) | | | (390) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 9 | | | 11 | | | (96) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 36 | | | 25 | | | 121 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 45 | | | $ | 36 | | | $ | 25 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 226 |
| | $ | 255 |
| | $ | 279 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
(Gain) loss on nonrecurring items | — |
| | (1 | ) | | 1 |
|
Depreciation and amortization | 337 |
| | 308 |
| | 303 |
|
Deferred income taxes and amortization of investment tax credits | (13 | ) | | 94 |
| | 78 |
|
Allowance for equity funds | (3 | ) | | (1 | ) | | (2 | ) |
Changes in regulatory assets and liabilities | 83 |
| | 50 |
| | 131 |
|
Deferred energy | (11 | ) | | (16 | ) | | (21 | ) |
Amortization of deferred energy | 16 |
| | 16 |
| | (107 | ) |
Other, net | 14 |
| | (3 | ) | | — |
|
Changes in other operating assets and liabilities: | | | | | |
Accounts receivable and other assets | 5 |
| | 6 |
| | 26 |
|
Inventories | (1 | ) | | 6 |
| | 7 |
|
Accrued property, income and other taxes | (35 | ) | | (26 | ) | | 63 |
|
Accounts payable and other liabilities | 1 |
| | (23 | ) | | 13 |
|
Net cash flows from operating activities | 619 |
| | 665 |
| | 771 |
|
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (298 | ) | | (270 | ) | | (335 | ) |
Acquisitions | — |
| | (77 | ) | | — |
|
Proceeds from sale of assets | 1 |
| | 4 |
| | — |
|
Net cash flows from investing activities | (297 | ) | | (343 | ) | | (335 | ) |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from issuance of long-term debt | 573 |
| | 91 |
| | — |
|
Repayments of long-term debt and financial and capital lease obligations | (840 | ) | | (89 | ) | | (224 | ) |
Dividends paid | — |
| | (548 | ) | | (469 | ) |
Net cash flows from financing activities | (267 | ) | | (546 | ) | | (693 | ) |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 55 |
| | (224 | ) | | (257 | ) |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 66 |
| | 290 |
| | 547 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 121 |
| | $ | 66 |
| | $ | 290 |
|
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Nevada Power Company together withand its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Nevada Power and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2018, 20172021, 2020 and 2016.2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Allowance for Doubtful AccountsCredit Losses
Accounts receivableTrade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts.credit losses. The allowance for doubtful accountscredit losses is based on Nevada Power's assessment of the collectibilitycollectability of amounts owed to Nevada Power by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Nevada Power primarily utilizes credit loss history. However, Nevada Power may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Nevada Power also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The changechanges in the balance of the allowance for doubtful accounts,credit losses, which is included in accounts receivable,trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | 2018 | | 2017 | | 2016 | | 2021 | | 2020 | | 2019 |
Beginning balance | $ | 16 |
| | $ | 12 |
| | $ | 13 |
| Beginning balance | $ | 19 | | | $ | 15 | | | $ | 16 | |
Charged to operating costs and expenses, net | 15 |
| | 15 |
| | 16 |
| Charged to operating costs and expenses, net | 13 | | | 13 | | | 12 | |
Write-offs, net | (15 | ) | | (11 | ) | | (17 | ) | Write-offs, net | (14) | | | (9) | | | (13) | |
Ending balance | $ | 16 |
| | $ | 16 |
| | $ | 12 |
| Ending balance | $ | 18 | | | $ | 19 | | | $ | 15 | |
Derivatives
Nevada Power employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.
For Nevada Power's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies totaling $56$64 million and $69 million as of December 31, 20182021 and 2017, and fuel, which includes coal stock, stored natural gas and fuel oil, totaling $5 million and $3 million as of December 31, 2018 and 2017, respectively.2020. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Nevada Power capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.Public Utilities Commission of Nevada ("PUCN").
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Nevada Power's various regulatory authorities. Depreciation studies are completed by Nevada Power to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Nevada Power retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Nevada Power is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Nevada Power's AFUDC rate used during 20182021 and 20172020 was 7.95%7.14% and 8.09%7.43%, respectively.
Asset Retirement Obligations
Nevada Power recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Nevada Power's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2018,2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
Nevada Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Nevada Power's operating and right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly.
Income Taxes
Berkshire Hathaway includes Nevada Power in its consolidated United States federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimatedenacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property‑related basis differences and other various differences that Nevada Power deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Nevada Power's federal, state and local incomeunrecognized tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income taxbenefits are primarily included in other long-term liabilities that may result from these examinations, if any, is not expected to have a material impact on Nevada Power's consolidated financial results.the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Nevada Power uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Nevada Power expects to be entitled in exchange for those goods or services. Nevada Power records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Nevada Power's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of amounts not considered Customer Revenue within Accounting Standards Codification ("ASC")ASC 606, "Revenue from Contracts with Customers" and revenue recognized in accordance with ASC 840, "Leases".842, "Leases."
Revenue recognized is equal to what Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power's performance to date and includes billed and unbilled amounts. As of December 31, 20182021 and December 31, 2017, accounts2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $106$107 million and $111$104 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In addition, Nevada Power has recognized contract assets of $6 million and $8 million as of December 31, 2021 and 2020, respectively, due to Nevada Power's performance on certain contracts.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.
Segment Information
Nevada Power currently has one1 segment, which includes its regulated electric utility operations.
New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB ASC Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. Nevada Power adopted this guidance January 1, 2018 prospectively for the capitalization of the service cost component in the Consolidated Balance Sheets and retrospectively for the presentation of the service cost component and the other components of net benefit cost in the Consolidated Statements of Operations applying the practical expedient to use the amounts previously disclosed in the Notes to Consolidated Financial Statements as the estimation basis for applying the retrospective presentation requirement. As a result, amounts other than the service cost for pension and other postretirement benefit plans for the years ended December 31, 2017 and 2016 of $2 million and $3 million, respectively, have been reclassified to Other, net in the Consolidated Statements of Operations.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Nevada Power adopted this guidance effective January 1, 2018 which did not have a material impact on its Consolidated Financial Statements.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. Nevada Power adopted this guidance retrospectively effective January 1, 2018 which did not have a material impact on its Consolidated Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases," ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption and ASU No. 2018-20 that provides targeted improvements to lessor accounting, such as the handling of sales and other similar taxes. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. Nevada Power adopted this guidance effective January 1, 2019, for all contracts currently in effect. Nevada Power is finalizing its implementation efforts relative to the new guidance and currently expects to recognize operating lease right of use assets and lease liabilities of approximately $15 million based on the contracts currently in-effect. Nevada Power currently does not believe the adoption of the new guidance will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize Customer Revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. Nevada Power adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,793 | | | $ | 3,690 | |
Transmission | 45 - 70 years | | 1,503 | | | 1,468 | |
Distribution | 20 - 65 years | | 3,920 | | | 3,771 | |
General and intangible plant | 5 - 65 years | | 836 | | | 791 | |
Utility plant | | | 10,052 | | | 9,720 | |
Accumulated depreciation and amortization | | | (3,406) | | | (3,162) | |
Utility plant, net | | | 6,646 | | | 6,558 | |
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
Plant, net | | | 6,647 | | | 6,559 | |
Construction work-in-progress | | | 244 | | | 142 | |
Property, plant and equipment, net | | | $ | 6,891 | | | $ | 6,701 | |
|
| | | | | | | | | |
| Depreciable Life | | 2018 | | 2017 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,720 |
| | $ | 3,707 |
|
Distribution | 20 - 65 years | | 3,411 |
| | 3,314 |
|
Transmission | 45 - 70 years | | 1,867 |
| | 1,860 |
|
General and intangible plant | 5 - 65 years | | 848 |
| | 793 |
|
Utility plant | | | 9,846 |
| | 9,674 |
|
Accumulated depreciation and amortization | | | (3,076 | ) | | (2,871 | ) |
Utility plant, net | | | 6,770 |
| | 6,803 |
|
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 |
| | 1 |
|
Plant, net | | | 6,771 |
| | 6,804 |
|
Construction work-in-progress | | | 97 |
| | 73 |
|
Property, plant and equipment, net | | | $ | 6,868 |
| | $ | 6,877 |
|
Almost all of Nevada Power's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Nevada Power's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2018, 20172021, 2020 and 20162019 was 3.2%., 3.1%, and 3.3%, respectively. Nevada Power is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2017.
Construction work-in-progress is primarily related to the construction of regulated assets.
In January 2018, Nevada Power revised its electric depreciation rates based on the results of a new depreciation study performed in 2017, the most significant impact of which was shorter estimated useful lives at the Navajo Generating Station and longer average service lives for various other utility plant groups. The net effect of these changes increased depreciation and amortization expense by $7 million for the year ended December 31, 2018, based on depreciable plant balances at the time of the change.
Acquisitions
In April 2017, Nevada Power purchased the remaining 25% interest in the Silverhawk natural gas-fueled generating facility for $77 million. The Public Utilities Commission of Nevada ("PUCN") approved the purchase of the facility in Nevada Power's triennial Integrated Resource Plan filing in December 2015. The purchase price was allocated to the assets acquired, consisting primarily of generation utility plant, and no significant liabilities were assumed.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements, Nevada Power, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Nevada Power accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Nevada Power's share of the expenses of these facilities.
The amounts shown in the table below represent Nevada Power's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 20182021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Nevada | | | | | | Construction |
| Power's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Navajo Generating Station(1) | 11 | % | | $ | 5 | | | $ | 5 | | | $ | — | |
ON Line Transmission Line | 19 | | | 120 | | | 23 | | | 1 | |
Other transmission facilities | Various | | 61 | | | 32 | | | — | |
Total | | | $ | 186 | | | $ | 60 | | | $ | 1 | |
(1)Represents Nevada Power's proportionate share of capitalized asset retirement costs to retire the Navajo Generating Station, which was shut down in November 2019.
|
| | | | | | | | | | | | | | |
| Nevada | | | | | | Construction |
| Power's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Navajo Generating Station | 11 | % | | $ | 223 |
| | $ | 176 |
| | $ | — |
|
ON Line Transmission Line | 24 |
| | 147 |
| | 19 |
| | 1 |
|
Other transmission facilities | Various |
| | 67 |
| | 27 |
| | — |
|
Total | | | $ | 437 |
| | $ | 222 |
| | $ | 1 |
|
(5) Leases
(5)The following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 10 | | | $ | 12 | |
Finance leases | 326 | | | 351 | |
Total right-of-use assets | $ | 336 | | | $ | 363 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 13 | | | $ | 15 | |
Finance leases | 336 | | | 361 | |
Total lease liabilities | $ | 349 | | | $ | 376 | |
The following table summarizes Nevada Power's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 | | |
| | | | | | | |
Variable | $ | 449 | | | $ | 434 | | | $ | 434 | | | |
Operating | 2 | | | 3 | | | 3 | | | |
Finance: | | | | | | | |
Amortization | 13 | | | 12 | | | 13 | | | |
Interest | 28 | | | 29 | | | 37 | | | |
| | | | | | | |
Total lease costs | $ | 492 | | | $ | 478 | | | $ | 487 | | | |
| | | | | | | |
Weighted-average remaining lease term (years): | | | | | | | |
Operating leases | 5.7 | | 6.5 | | 7.5 | | |
Finance leases | 28.7 | | 28.7 | | 30.6 | | |
| | | | | | | |
Weighted-average discount rate: | | | | | | | |
Operating leases | 4.5 | % | | 4.5 | % | | 4.5 | % | | |
Finance leases | 8.6 | % | | 8.6 | % | | 8.7 | % | | |
The following table summarizes Nevada Power's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 | | |
| | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | |
Operating cash flows from operating leases | $ | (3) | | | $ | (3) | | | $ | (3) | | | |
Operating cash flows from finance leases | (29) | | | (34) | | | (37) | | | |
Financing cash flows from finance leases | (16) | | | (15) | | | (14) | | | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | | | |
Operating leases | $ | — | | | $ | 1 | | | $ | — | | | |
Finance leases | 1 | | | 9 | | | 9 | | | |
Nevada Power has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 3 | | | $ | 54 | | | $ | 57 | |
2023 | 2 | | | 44 | | | 46 | |
2024 | 3 | | | 44 | | | 47 | |
2025 | 2 | | | 43 | | | 45 | |
2026 | 3 | | | 43 | | | 46 | |
Thereafter | 2 | | | 448 | | | 450 | |
Total undiscounted lease payments | 15 | | | 676 | | | 691 | |
Less - amounts representing interest | (2) | | | (340) | | | (342) | |
Lease liabilities | $ | 13 | | | $ | 336 | | | $ | 349 | |
Operating and Finance Lease Obligations
Nevada Power's lease obligation primarily consists of a transmission line, One Nevada Transmission Line ("ON Line"), which was placed in-service on December 31, 2013. Nevada Power and Sierra Pacific, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the necessary procedures to change the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved ownership percentage change from Nevada Power to Sierra Pacific. The term of the lease is 41 years with the agreement ending December 31, 2054. Total ON Line finance lease obligations of $286 million and $295 million were included on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. See Note 2 for further discussion of Nevada Power's other lease obligations.
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. Nevada Power's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred energy costs | 1 year | | $ | 273 | | | $ | 39 | |
Decommissioning costs | 2 years | | 169 | | | 230 | |
Unrealized loss on regulated derivative contracts | 1 year | | 117 | | | 11 | |
Merger costs from 1999 merger | 23 years | | 110 | | | 115 | |
Deferred operating costs | 12 years | | 93 | | | 119 | |
Asset retirement obligations | 6 years | | 73 | | | 70 | |
ON Line deferrals | 32 years | | 42 | | | 43 | |
Legacy meters | 11 years | | 41 | | | 45 | |
Employee benefit plans(1) | 8 years | | 11 | | | 50 | |
| | | | | |
Other | Various | | 90 | | | 72 | |
Total regulatory assets | | | $ | 1,019 | | | $ | 794 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 291 | | | $ | 48 | |
Noncurrent assets | | | 728 | | | 746 | |
Total regulatory assets | | | $ | 1,019 | | | $ | 794 | |
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Decommissioning costs(2) | 5 years | | $ | 222 |
| | $ | 231 |
|
Deferred operating costs | 10 years | | 152 |
| | 169 |
|
Merger costs from 1999 merger | 26 years | | 125 |
| | 130 |
|
Employee benefit plans(1) | 8 years | | 105 |
| | 89 |
|
Asset retirement obligations | 7 years | | 68 |
| | 72 |
|
Abandoned projects | 2 years | | 46 |
| | 58 |
|
Legacy meters | 14 years | | 53 |
| | 56 |
|
ON Line deferrals | 35 years | | 46 |
| | 47 |
|
Deferred energy costs | 1 year | | 47 |
| | 46 |
|
Other | Various | | 53 |
| | 71 |
|
Total regulatory assets | | | $ | 917 |
| | $ | 969 |
|
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 39 |
| | $ | 28 |
|
Other assets | | | 878 |
| | 941 |
|
Total regulatory assets | | | $ | 917 |
| | $ | 969 |
|
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
| |
(1) | Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized. |
| |
(2) | Amount includes regulatory assets with an indeterminate life of $81 million as of December 31, 2018. |
Nevada Power had regulatory assets not earning a return on investment of $334$371 million and $363$288 million as of December 31, 20182021 and 2017,2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, asset retirement obligations,AROs, deferred operating costs, a portion of the employee benefit plans, losses on reacquired debt and deferred energy costs.
Regulatory Liabilities
Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Nevada Power's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 603 | | | $ | 647 | |
Cost of removal(2) | 31 years | | 348 | | | 340 | |
| | | | | |
| | | | | |
| | | | | |
Other | Various | | 198 | | | 226 | |
Total regulatory liabilities | | | $ | 1,149 | | | $ | 1,213 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 49 | | | $ | 50 | |
Noncurrent liabilities | | | 1,100 | | | 1,163 | |
Total regulatory liabilities | | | $ | 1,149 | | | $ | 1,213 | |
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Deferred income taxes(1) | 27 years | | $ | 677 |
| | $ | 670 |
|
Cost of removal(2) | 33 years | | 320 |
| | 307 |
|
Impact fees(3) | 4 years | | 86 |
| | 89 |
|
Energy efficiency program | 1 year | | 24 |
| | 27 |
|
Other | Various | | 79 |
| | 28 |
|
Total regulatory liabilities | | | $ | 1,186 |
| | $ | 1,121 |
|
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 49 |
| | $ | 91 |
|
Other long-term liabilities | | | 1,137 |
| | 1,030 |
|
Total regulatory liabilities | | | $ | 1,186 |
| | $ | 1,121 |
|
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
| |
(1) | Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. Amount includes regulatory liabilities with an indeterminate life of $82 million as of December 31, 2018. See Note 9 for further discussion of 2017 Tax Reform impacts. |
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
| |
(2) | Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. |
| |
(3) | Amounts reduce rate base or otherwise accrue a carrying cost. |
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Natural Disaster Protection Plan ("NDPP")
In March 2021, Nevada Power filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Nevada Power filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Nevada Power and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
Regulatory Rate Review
In June 2017,2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increasereduction of $29$96 million or 2%, but requested no incrementalan annual revenue relief.reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2017,2020, the PUCN issued ana final order which reduced Nevada Power's revenue requirement by $26 million and requiresdirecting Nevada Power to share 50% of regulatory earnings above 9.7%. In January 2018, Nevada Power filed a petition for clarification of certain findings and directives incontinue the order and intervening parties filed motions for reconsideration. In December 2018, the PUCN issued an order granting petitions for clarification and reconsideration and modified the December 2017 order requiring Nevada Powerearning sharing mechanism subject to record additional expense for carrying charges on impact fees received but not yet included in rates. As a result of the order, Nevada Power recorded expense of $44 million in 2018, which consists of regulatory earnings sharing of $38 million and carrying charges of $6 million, and $28 million in December 2017, primarily dueany modifications made to the reduction of aearning sharing mechanism pursuant to an alternative rate-making ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory asset to return to customers revenue collected for costs not incurred.rate review. The new rates were effective February 15, 2018.
2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United States federal corporate income tax rate from 35% to 21%. In February 2018, Nevada Power made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. The filings supported an annual rate reduction of $59 million. In March 2018, the PUCN issued an order approving the rate reduction proposed by Nevada Power. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing Nevada Power to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effectiveon January 1, 2018. Subsequently, Nevada Power filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Nevada Power filed a petition for judicial review.2021.
In March 2018, the FERC issued a Show Cause Order related to 2017 Tax Reform. In May 2018, in response to the Show Cause Order, Nevada Power proposed a reduction to transmission and certain ancillary service rates under the NV Energy OATT for the lower annual income tax expense anticipated from 2017 Tax Reform. In November 2018, FERC issued an order accepting the proposed rate reduction effective March 21, 2018 as filed and refunds to customers were made in December 2018 totaling $1 million for Nevada Power. In addition, FERC issued a notice of proposed rulemaking on public utility transmission rate changes to address accumulated deferred income taxes.
Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")
EEPR was established to allow Nevada Power to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Nevada Power and approved by the PUCN in integrated resource plan proceedings. To the extentWhen Nevada Power's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, Nevada Powerit is requiredobligated to refund to customers EEIRenergy efficiency implementation revenue previously collected for that year. In March 2018,2021, Nevada Power filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2017,2020, including carrying charges. In September 2018,August 2021, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 20172020 revenue and reset the rates as filed effective October 1, 2018.2021. The EEIR liability for Nevada Power is $9 million and $10$8 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 20182021 and 2017, respectively.2020.
Chapter 704B Applications
(7)Short-term Debt and Credit Facilities
Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one megawatt ("MW") or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution-only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms.
The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs.
In October 2016, Wynn Las Vegas, LLC ("Wynn"), became a distribution-only service customer and started procuring energy from another energy supplier. In April 2017, Wynn filed a motion with the PUCN seeking relief from the January 2016 order that established the impact fee that was paid in September 2016 and requested the PUCN adopt an alternative impact fee and revise on-going charges associated with retirement of assets and high cost renewable contracts. In September 2018, the PUCN granted relief requiring Nevada Power to credit $3 million as an offset against Wynn's remaining impact fee obligation. In October 2018, Wynn elected to pay the net present value lump sum of its Renewable Base Tariff Energy Rate ("R-BTER") obligation of $2 million, net of the $3 million credit. The PUCN ordered Nevada Power to establish a regulatory liability of $5 million amortized in equal monthly installments through December 2022 and to establish a regulatory asset of $3 million for the impact fee credit.
In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution-only service customer of Nevada
Power. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee monthly for six years and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution-only service customer of Nevada Power. In February 2018, Caesars became a distribution-only service customer, started procuring energy from another energy supplier for its eligible meters in the Nevada Power service territory and began paying Nevada Power impact fees of $44 million in 72 equal monthly payments.
In June 2018, Station Casinos LLC ("Station"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution-only service customer of Nevada Power. In October 2018, the PUCN approved an order allowing Station to purchase energy from alternative providers subject to conditions, including paying an impact fee of $15 million. In November 2018, Station filed a petition for reconsideration with the PUCN to allow Station to pay its share of the R-BTER in a single lump sum, receive a credit for a portion of impact fees previously paid by past 704B applicants and receive a credit for a portion of incremental transmission revenue associated with expected sales to others. In December 2018, the PUCN issued an order granting reconsideration and reaffirming the October 2018 order.
Emissions Reduction and Capacity Retirement Plan ("ERCR Plan")
In March 2017, Nevada Power retired Reid Gardner Unit 4, a 257-MW coal-fueled generating facility. The early retirement was approved by the PUCN in December 2016 as a part offollowing table summarizes Nevada Power's second amendment to the ERCR Plan. The remaining net book valueavailability under its credit facilities as of $151 million was moved from property, plant and equipment, net to noncurrent regulatory assets on the Consolidated Balance Sheet in March 2017, in compliance with the ERCR Plan. Refer to Note 12 for additional information on the ERCR Plan.December 31 (in millions):
| | | | | | | | | | | | | | |
| | 2021 | | 2020 |
Credit facilities | | $ | 400 | | | $ | 400 | |
Short-term debt | | (180) | | | — | |
| | | | |
Net credit facilities | | $ | 220 | | | $ | 400 | |
(6)Credit Facility
Nevada Power has a $400 million secured credit facility expiring in June 20212024 with a one-yearan unlimited number of maturity extension optionoptions, subject to lender consent. The credit facility, which is for general corporate purposes and provide for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long‑term debt securities. As of December 31, 20182021 and 2017,2020, Nevada Power had no borrowings of $180 million and $— million, respectively, outstanding under the credit facility. As of December 31, 2021, the weighted average interest rate on borrowings outstanding was 0.86%. Amounts due under Nevada Power's credit facility are collateralized by Nevada Power's general and refunding mortgage bonds. The credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
(7) Long-TermAs of December 31, 2021, Nevada Power had $15 million of a fully available letter of credit issued under committed arrangements in support of certain transactions required by a third party and has provisions that automatically extend the annual expiration date for an additional year unless the issuing bank elects not to renew the letter of credit prior to the expiration date.
(8) Long-term Debt and Financial and Capital Lease Obligations
Nevada Power's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
General and refunding mortgage securities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
3.700% Series CC, due 2029 | $ | 500 | | | $ | 497 | | | $ | 496 | |
2.400% Series DD, due 2030 | 425 | | | 422 | | | 422 | |
6.650% Series N, due 2036 | 367 | | | 359 | | | 359 | |
6.750% Series R, due 2037 | 349 | | | 346 | | | 346 | |
5.375% Series X, due 2040 | 250 | | | 248 | | | 248 | |
5.450% Series Y, due 2041 | 250 | | | 239 | | | 237 | |
3.125% Series EE, due 2050 | 300 | | | 297 | | | 297 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.875% Pollution Control Bonds Series 2017A, due 2032(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017, due 2036(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017B, due 2039(1) | 13 | | | 13 | | | 13 | |
| | | | | |
| | | | | |
| | | | | |
Total long-term debt | $ | 2,534 | | | $ | 2,499 | | | $ | 2,496 | |
| | | | | |
Reflected as: | | | | | |
| | | | | |
| | | | | |
Total long-term debt | | | $ | 2,499 | | | $ | 2,496 | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
General and refunding mortgage securities: | | | | | |
6.500% Series O, due 2018 | $ | — |
| | $ | — |
| | $ | 324 |
|
6.500% Series S, due 2018 | — |
| | — |
| | 499 |
|
7.125% Series V, due 2019 | 500 |
| | 500 |
| | 499 |
|
6.650% Series N, due 2036 | 367 |
| | 358 |
| | 357 |
|
6.750% Series R, due 2037 | 349 |
| | 346 |
| | 346 |
|
5.375% Series X, due 2040 | 250 |
| | 247 |
| | 247 |
|
5.450% Series Y, due 2041 | 250 |
| | 236 |
| | 236 |
|
2.750%, Series BB, due 2020 | 575 |
|
| 574 |
|
| — |
|
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.800% Pollution Control Bonds Series 2017A, due 2032(1) | 40 |
| | 40 |
| | 40 |
|
1.600% Pollution Control Bonds Series 2017, due 2036(1) | 40 |
| | 39 |
| | 39 |
|
1.600% Pollution Control Bonds Series 2017B, due 2039(1) | 13 |
| | 13 |
| | 13 |
|
Capital and financial lease obligations - 2.750% to 11.600%, due through 2054 | 463 |
| | 463 |
| | 475 |
|
Total long-term debt and financial and capital leases | $ | 2,847 |
| | $ | 2,816 |
| | $ | 3,075 |
|
| | | | | |
Reflected as: | | | | | |
Current portion of long-term debt and financial and capital lease obligations | | | $ | 520 |
| | $ | 842 |
|
Long-term debt and financial and capital lease obligations | | | 2,296 |
| | 2,233 |
|
Total long-term debt and financial and capital leases | | | $ | 2,816 |
| | $ | 3,075 |
|
(1)Subject to mandatory purchase by Nevada Power in March 2023 at which date the interest rate may be adjusted.
| |
(1) | Subject to mandatory purchase by Nevada Power in May 2020 at which date the interest rate may be adjusted from time to time. |
Annual Payment on Long-Term Debt and Financial and Capital Leases
The annual repayments of long-term debt and capital and financial leases for the years beginning January 1, 20192022 and thereafter, are as follows (in millions):
| | | | | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
2027 and thereafter | $ | 2,534 | | | | | |
| | | | | |
Unamortized premium, discount and debt issuance cost | (35) | | | | | |
| | | | | |
| | | | | |
Total | $ | 2,499 | | | | | |
|
| | | | | | | | | | | | |
| | Long-term | | Capital and Financial | | |
| | Debt | | Lease Obligations | | Total |
| | | | | | |
2019 | | $ | 500 |
| | $ | 78 |
| | $ | 578 |
|
2020 | | 575 |
| | 77 |
| | 652 |
|
2021 | | — |
| | 80 |
| | 80 |
|
2022 | | — |
| | 76 |
| | 76 |
|
2023 | | — |
| | 52 |
| | 52 |
|
Thereafter | | 1,309 |
| | 709 |
| | 2,018 |
|
Total | | 2,384 |
| | 1,072 |
| | 3,456 |
|
Unamortized premium, discount and debt issuance cost | | (31 | ) | | — |
| | (31 | ) |
Executory costs | | — |
| | (74 | ) | | (74 | ) |
Amounts representing interest | | — |
| | (535 | ) | | (535 | ) |
Total | | $ | 2,353 |
| | $ | 463 |
| | $ | 2,816 |
|
In January 2019,2022, Nevada Power issued $500entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its 3.70% Generalexisting secured credit facility and Refunding Mortgage Notes, Series CC, due May 2029.for general corporate purposes.
The issuance of General and Refunding Mortgage Securities by Nevada Power is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2018,2021, approximately $8.5$9.4 billion (based on original cost) of Nevada Power's property was subject to the liens of the mortgages.
Financial and Capital Lease Obligations
(9) Income Taxes
In 1984, Nevada Power entered into a 30-year capital lease
Income tax expense consists of the following for the Pearson Building with five, five-year renewal options beginning in year 2015. In February 2010, Nevada Power amended this capital lease agreement to include the leaseyears ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current – Federal | $ | 37 | | | $ | 57 | | | $ | 105 | |
| | | | | |
Deferred – Federal | — | | | (10) | | | (31) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Investment tax credits | — | | | — | | | (1) | |
Total income tax expense | $ | 37 | | | $ | 47 | | | $ | 73 | |
A reconciliation of the adjoining parking lot andfederal statutory income tax rate to exercise threethe effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (11) | | | (8) | | | — | |
| | | | | |
| | | | | |
Other | 1 | | | 1 | | | 1 | |
Effective income tax rate | 11 | % | | 14 | % | | 22 | % |
The net deferred income tax liability consists of the five-year renewal options beginning in year 2015. There remain two additional renewal options which could extend the lease an additional ten years. Capital assets of $23 million and $24 million were included in property, plant and equipment, netfollowing as of December 31 2018(in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 195 | | | $ | 206 | |
Operating and finance leases | 73 | | | 79 | |
Customer advances | 25 | | | 19 | |
Unamortized contract value | 25 | | | 8 | |
Other | 8 | | | 15 | |
Total deferred income tax assets | 326 | | | 327 | |
| | | |
| | | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (800) | | | (800) | |
Regulatory assets | (204) | | | (176) | |
Operating and finance leases | (70) | | | (76) | |
Other | (34) | | | (13) | |
Total deferred income tax liabilities | (1,108) | | | (1,065) | |
Net deferred income tax liability | $ | (782) | | | $ | (738) | |
| | | |
| | | |
| | | |
| | | |
| | | |
The United States Internal Revenue Service has closed its examination of NV Energy's consolidated income tax returns through December 31, 2008, and 2017, respectively.effectively settled its examination of Nevada Power's income tax return for the short year ended December 31, 2013, and the statute of limitations has expired for NV Energy's consolidated income tax returns through the short year ended December 19, 2013. The closure or effective settlement of examinations, or the expiration of the statute of limitations may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
In 2007,
(10) Employee Benefit Plans
Nevada Power entered intois a 20-year lease, with three 10-year renewal options, to occupy landparticipant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and buildinga supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for its Beltway Complex operations center in southern Nevada.eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power accountsdid not make any contributions to the Qualified Pension Plan for the building portionyears ended December 31, 2021, 2020 and 2019. Nevada Power contributed $1 million to the Non-Qualified Pension Plans for the years ended December 31, 2021, 2020 and 2019. Nevada Power did not make any contributions to the Other Postretirement Plans for the years ended December 31, 2021, 2020 and 2019. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the lease as a capital lease and the land portion of the lease as an operating lease. Nevada Power transferred operations to the facilities in June 2009. Capital assets of $6 million were included in property, plant and equipment, netfollowing as of December 31 2018(in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Qualified Pension Plan - | | | |
Other non-current assets | $ | 42 | | | $ | 8 | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (8) | | | (9) | |
| | | |
Other Postretirement Plans - | | | |
Other non-current assets | 8 | | | 4 | |
| | | |
(11) Asset Retirement Obligations
Nevada Power estimates its ARO liabilities based upon detailed engineering calculations of the amount and 2017.timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Nevada Power does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $348 million and $340 million as of December 31, 2021 and 2020, respectively.
The following table presents Nevada Power's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Waste water remediation | $ | 37 | | | $ | 36 | |
Evaporative ponds and dry ash landfills | 13 | | | 13 | |
| | | |
Solar | 3 | | | 3 | |
Other | 15 | | | 20 | |
Total asset retirement obligations | $ | 68 | | | $ | 72 | |
The following table reconciles the beginning and ending balances of Nevada Power's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 72 | | | $ | 74 | |
Change in estimated costs | — | | | 9 | |
| | | |
Retirements | (6) | | | (14) | |
Accretion | 2 | | | 3 | |
Ending balance | $ | 68 | | | $ | 72 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 19 | | | $ | 25 | |
Other long-term liabilities | 49 | | | 47 | |
| $ | 68 | | | $ | 72 | |
In 2008, Nevada Power signed an administrative order of consent as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the administrative order of consent, Nevada Power recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between Nevada Power and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station Unit No. 4, Nevada Power and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities as required under the administrative order of consent.
Certain of Nevada Power's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Nevada Power is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Management has identified legal obligations to retire generation plant assets specified in land leases for Nevada Power's jointly-owned Navajo Generating Station, retired in November 2019, and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Nevada Power's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has long-term energy purchaseestablished a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which qualifymay include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as capital leases. interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The leases were entered into betweenfollowing table, which excludes contracts that have been designated as normal under the years 1989normal purchases and 1990normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and became commercially operable through 1993. The terms ofreconciles those amounts presented on a net basis on the leasesConsolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 4 | | | | | $ | — | | | $ | — | | | $ | 4 | |
Commodity liabilities | — | | | | | (55) | | | (62) | | | (117) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 4 | | | | | $ | (55) | | | $ | (62) | | | $ | (113) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 26 | | | | | $ | — | | | $ | — | | | $ | 26 | |
Commodity liabilities | — | | | | | (3) | | | (8) | | | (11) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 26 | | | | | $ | (3) | | | $ | (8) | | | $ | 15 | |
(1)Nevada Power's commodity derivatives not designated as hedging contracts are for 30 years and expire between the years 2022-2023. Capital assets of $30 million and $34 million were included in property, plant and equipment,regulated rates. As of December 31, 2021 a regulatory asset of $113 million was recorded related to the net derivative liability of $113 million. As of December 31, 2020 a regulatory liability of $15 million was recorded related to the net derivative asset of $15 million.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 2018 and 2017, respectively.(in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases | Megawatt hours | | 1 | | | 1 | |
Natural gas purchases | Decatherms | | 119 | | | 124 | |
| | | | | |
Credit Risk
Nevada Power has master leasingis exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of which various piecescredit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of equipment qualify as capital leases. the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The remaining equipment is treated as operating leases. Lease terms under the master lease agreement are typically five to seven years. Capital assetsaggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $6 million and $3 million were included in property, plant and equipment, net as of December 31, 20182021 and 2017, respectively.2020, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
ON Line was placed in-service on December 31, 2013. The Nevada Utilities entered into a long-term transmission use agreement, in which the Nevada Utilities have 25% interest and Great Basin Transmission South, LLC has 75% interest. Refer to Note 4 for additional information. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 95% for Nevada Power and 5% for Sierra Pacific. The term is for 41 years with the agreement ending December 31, 2054. Payments began on January 31, 2014. ON Line assets of $387 million and $396 million were included in property, plant and equipment, net as of December 31, 2018 and 2017, respectively.
(13) Fair Value Measurements
| |
(8) | Fair Value Measurements
|
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
The following table presents Nevada Power's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
Money market mutual funds | 34 | | | — | | | — | | | 34 | |
Investment funds | 3 | | | — | | | — | | | 3 | |
| $ | 37 | | | $ | — | | | $ | 4 | | | $ | 41 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (117) | | | $ | (117) | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 26 | | | $ | 26 | |
Money market mutual funds | 21 | | | — | | | — | | | 21 | |
Investment funds | 2 | | | — | | | — | | | 2 | |
| $ | 23 | | | $ | — | | | $ | 26 | | | $ | 49 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (11) | | | $ | (11) | |
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2018: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 7 |
|
Money market mutual funds(1) | 104 |
| | — |
| | — |
| | 104 |
|
Investment funds | 1 |
| | — |
| | — |
| | 1 |
|
| $ | 105 |
| | $ | — |
| | $ | 7 |
| | $ | 112 |
|
| | | | | | | |
Liabilities - commodity derivatives | $ | — |
| | $ | — |
| | $ | (4 | ) | | $ | (4 | ) |
| | | | | | | |
As of December 31, 2017: | | | | | | | |
Assets - investment funds | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| | | | | | | |
Liabilities - commodity derivatives | $ | — |
| | $ | — |
| | $ | (3 | ) | | $ | (3 | ) |
| |
(1) | Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of December 31, 2018,2021, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.
Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Nevada Power's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Beginning balance | | $ | 15 | | | $ | (8) | | | $ | 3 | |
Changes in fair value recognized in regulatory assets or liabilities | | (90) | | | (17) | | | (21) | |
| | | | | | |
Settlements | | (38) | | | 40 | | | 10 | |
Ending balance | | $ | (113) | | | $ | 15 | | | $ | (8) | |
|
| | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
Beginning balance | | $ | (3 | ) | | $ | (14 | ) | | $ | (22 | ) |
Changes in fair value recognized in regulatory assets or liabilities | | 4 |
| | (3 | ) | | (4 | ) |
Settlements | | 2 |
| | 14 |
| | 12 |
|
Ending balance | | $ | 3 |
| | $ | (3 | ) | | $ | (14 | ) |
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,499 | | | $ | 3,067 | | | $ | 2,496 | | | $ | 3,245 | |
(14) Commitments and Contingencies
|
| | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,353 |
| | $ | 2,651 |
| | $ | 2,600 |
| | $ | 3,088 |
|
Tax Cuts and Jobs Act
The 2017 Tax Reform impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, limitations on bonus depreciation for utility property and the elimination of the deduction for production activities. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, Nevada Power reduced deferred income tax liabilities $787 million. As it was probable the change in deferred taxes would be passed back to customers through regulatory mechanisms, Nevada Power increased net regulatory liabilities by $792 million.
In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. Nevada Power recorded the impacts of the 2017 Tax Reform in December 2017 and believed all the impacts to be complete with the exception of the interpretation of the bonus depreciation rules. Nevada Power determined the amounts recorded and the interpretation relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. Nevada Power believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, Nevada Power finalized its provisional amounts and recorded a current tax benefit and deferred tax expense of $12 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform and Nevada Power's regulatory nature, Nevada Power reduced the associated deferred income tax liabilities $5 million and increased regulatory liabilities by the same amount.
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Current – Federal | $ | 84 |
| | $ | 62 |
| | $ | 68 |
|
Deferred – Federal | (13 | ) | | 95 |
| | 79 |
|
Uncertain tax positions | 2 |
| | — |
| | — |
|
Investment tax credits | (1 | ) | | (1 | ) | | (1 | ) |
Total income tax expense | $ | 72 |
| | $ | 156 |
| | $ | 146 |
|
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
Non-deductible expenses | 3 |
| | — |
| | — |
|
Effect of ratemaking | — |
| | 1 |
| | — |
|
Effect of tax rate change | — |
| | 1 |
| | — |
|
Other | — |
| | 1 |
| | (1 | ) |
Effective income tax rate | 24 | % | | 38 | % | | 34 | % |
The net deferred income tax liability consists of the following as of December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 209 |
| | $ | 201 |
|
Capital and financial leases | 97 |
| | 100 |
|
Employee benefits | 15 |
| | 18 |
|
Customer advances | 18 |
| | 14 |
|
Other | 9 |
| | 6 |
|
Total deferred income tax assets | 348 |
| | 339 |
|
| | | |
Deferred income tax liabilities: | | | |
Property related items | (799 | ) | | (796 | ) |
Regulatory assets | (196 | ) | | (206 | ) |
Capital and financial leases | (94 | ) | | (97 | ) |
Other | (8 | ) | | (7 | ) |
Total deferred income tax liabilities | (1,097 | ) | | (1,106 | ) |
Net deferred income tax liability | $ | (749 | ) | | $ | (767 | ) |
The United States Internal Revenue Service has closed its examination of NV Energy’s consolidated income tax returns through December 31, 2008, and the statute of limitations has expired for NV Energy’s consolidated income tax returns through the short year ended December 19, 2013. The statute of limitations expiring may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
(10) Employee Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power contributed $19 million, $1 million and $36 million to the Qualified Pension Plan for the year ended December 31, 2018, 2017 and 2016, respectively. Nevada Power contributed $1 million, $1 million and $- million to the Non-Qualified Pension Plans for the year ended December 31, 2018, 2017 and 2016, respectively. Nevada Power contributed $- million to the Other Postretirement Plans for the year ended December 31, 2018 and did not make any contributions for the years ended December 31, 2017 and 2016. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
Qualified Pension Plan - | | | |
Other long-term liabilities | $ | (26 | ) | | $ | (23 | ) |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1 | ) | | (1 | ) |
Other long-term liabilities | (9 | ) | | (10 | ) |
| | | |
Other Postretirement Plans - | | | |
Other long-term liabilities | (1 | ) | | 1 |
|
(11) Asset Retirement Obligations
Nevada Power estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Nevada Power does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $320 million and $307 million as of December 31, 2018 and 2017, respectively.
The following table presents Nevada Power's ARO liabilities by asset type as of December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Waste water remediation | $ | 37 |
| | $ | 39 |
|
Evaporative ponds and dry ash landfills | 12 |
| | 11 |
|
Asbestos | 5 |
| | 3 |
|
Solar | 2 |
| | 3 |
|
Other | 27 |
| | 24 |
|
Total asset retirement obligations | $ | 83 |
| | $ | 80 |
|
The following table reconciles the beginning and ending balances of Nevada Power's ARO liabilities for the years ended December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 80 |
| | $ | 83 |
|
Change in estimated costs | 11 |
| | 6 |
|
Retirements | (11 | ) | | (13 | ) |
Accretion | 3 |
| | 4 |
|
Ending balance | $ | 83 |
| | $ | 80 |
|
| | | |
Reflected as: | | | |
Other current liabilities | $ | 13 |
| | $ | 4 |
|
Other long-term liabilities | 70 |
| | 76 |
|
| $ | 83 |
| | $ | 80 |
|
In 2008, Nevada Power signed an administrative order of consent as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the administrative order of consent, Nevada Power recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between Nevada Power and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station Unit No. 4, Nevada Power and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities as required under the administrative order of consent.
Certain of Nevada Power's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Nevada Power is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Management has identified legal obligations to retire generation plant assets specified in land leases for Nevada Power's jointly-owned Navajo Generating Station and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Nevada Power's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
| |
(12) | Commitments and Contingencies
|
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Senate Bill 123
In June 2013, the Nevada State Legislature passed Senate Bill No. 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable facilities and other generating facilities. In May 2014, Nevada Power filed its Emissions Reduction and Capacity Replacement Plan ("ERCR PlanPlan") in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.
In compliance with Senate Bill No.SB 123, Nevada Power retired 557 MWs of coal-fueled generation in 2017 and will retire an additional 255 MWs of coal-fueled generation in 2019.2019 in addition to the 557 MWs of coal-fueled generation retired in 2017. Consistent with the Emissions Reduction and Capacity ReplacementERCR Plan, ("ERCR Plan"), between 2014 and 2016, Nevada Power acquired 536 MWs of natural gas generating resources, executed long-term power purchase agreements for 200 MWs of nameplate renewable energy capacity and constructed a 15-MW solar photovoltaic facility. Nevada Power has the option to acquire 35 MWs of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval.
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Commitments
Nevada Power has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 20182021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 713 | | | $ | 458 | | | $ | 346 | | | $ | 348 | | | $ | 352 | | | $ | 3,250 | | | $ | 5,467 | |
Fuel and capacity contract commitments (not commercially operable) | 20 | | | 60 | | | 181 | | | 212 | | | 211 | | | 4,302 | | | 4,986 | |
Construction commitments | 141 | | | 209 | | | — | | | — | | | — | | | — | | | 350 | |
Easements | 4 | | | 5 | | | 2 | | | 2 | | | 2 | | | 52 | | | 67 | |
Maintenance, service and other contracts | 51 | | | 34 | | | 23 | | | 18 | | | 14 | | | 33 | | | 173 | |
Total commitments | $ | 929 | | | $ | 766 | | | $ | 552 | | | $ | 580 | | | $ | 579 | | | $ | 7,637 | | | $ | 11,043 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 612 |
| | $ | 459 |
| | $ | 379 |
| | $ | 383 |
| | $ | 386 |
| | $ | 4,925 |
| | $ | 7,144 |
|
Fuel and capacity contract commitments (not commercially operable) | — |
| | 1 |
| | 6 |
| | 40 |
| | 40 |
| | 982 |
| | 1,069 |
|
Operating leases and easements | 10 |
| | 7 |
| | 7 |
| | 8 |
| | 7 |
| | 59 |
| | 98 |
|
Maintenance, service and other contracts | 46 |
| | 41 |
| | 44 |
| | 37 |
| | 23 |
| | 26 |
| | 217 |
|
Total commitments | $ | 668 |
| | $ | 508 |
| | $ | 436 |
| | $ | 468 |
| | $ | 456 |
| | $ | 5,992 |
| | $ | 8,528 |
|
Fuel and Capacity Contract Commitments
Purchased Power
Nevada Power has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 20192026 to 2067. Purchased power includes estimated payments for contracts which meet the definition of a lease.lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Nevada Power's lease commitments.
Natural Gas
Nevada Power's gas transportation contracts expire from 2022 to 2039 and the gas supply contracts expires from 2022 to 2023.
Fuel and Capacity Contract Commitments - Not Commercially Operable
Nevada Power has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Construction Commitments
Nevada Power's construction commitments included in the table above relate to firm commitments and include costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada and certain other generating plant projects.
Easements
Nevada Power has non-cancelable easements for land. Operations and maintenance expense on non-cancelable easements totaled $4 million, $4 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Maintenance, Service and Other Contracts
Nevada Power has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2022 to 2031.
(15) Revenues from Contracts with Customers
The following table summarizes Nevada Power's Customer Revenue by customer class for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Retail: | | | | | |
Residential | $ | 1,207 | | | $ | 1,145 | | | $ | 1,141 | |
Commercial | 414 | | | 384 | | | 441 | |
Industrial | 386 | | | 345 | | | 433 | |
Other | 14 | | | 12 | | | 20 | |
Total fully bundled | 2,021 | | | 1,886 | | | 2,035 | |
Distribution only service | 22 | | | 24 | | | 31 | |
Total retail | 2,043 | | | 1,910 | | | 2,066 | |
Wholesale, transmission and other | 74 | | | 62 | | | 57 | |
Total Customer Revenue | 2,117 | | | 1,972 | | | 2,123 | |
Other revenue | 22 | | | 26 | | | 25 | |
Total revenue | $ | 2,139 | | | $ | 1,998 | | | $ | 2,148 | |
(16) Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2021 and December 31, 2020, consist of funds restricted by the PUCN for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| December 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 33 | | | $ | 25 | |
Restricted cash and cash equivalents included in other current assets | 12 | | | 11 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 45 | | | $ | 36 | |
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 115 | | | $ | 115 | | | $ | 126 | |
Income taxes paid | $ | 63 | | | $ | 50 | | | $ | 113 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 53 | | | $ | 32 | | | $ | 49 | |
(17) Related Party Transactions
Nevada Power has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Nevada Power under this agreement totaled $3 million, $2 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Kern River Gas Transmission Company, an indirect subsidiary of BHE, provided natural gas transportation and other services to Nevada Power of $52 million for the years ended December 31, 2021, 2020 and 2019. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $4 million.
Nevada Power provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $3 million, $3 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively. There were no receivables associated with these services as of December 31, 2021 and 2020. PacifiCorp provided electricity and the sale of renewable energy credits to Nevada Power of $— million, $1 million and $— million for the years ended December 31, 2021, 2020, and 2019, respectively. There were no payables associated with these transactions as of December 31, 2021 and 2020.
Nevada Power provided electricity to Sierra Pacific of $179 million, $106 million and $84 million for the years ended December 31, 2021, 2020 and 2019, respectively. Receivables associated with these transactions were $13 million as of December 31, 2021 and 2020. Nevada Power purchased electricity from Sierra Pacific of $43 million, $34 million and $25 million for the years ended December 31, 2021, 2020 and 2019, respectively. Payables associated with these transactions were $— million and $1 million as of December 31, 2021 and 2020, respectively.
Nevada Power incurs intercompany administrative and shared facility costs with NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. Nevada Power provided services to NV Energy of $1 million, $— million and $— million for each of the years ending December 31, 2021, 2020 and 2019, respectively. NV Energy provided services to Nevada Power of $9 million for the years ending December 31, 2021, 2020 and 2019. Nevada Power provided services to Sierra Pacific of $25 million, $26 million and $26 million for the years ended December 31, 2021, 2020 and 2019, respectively. Sierra Pacific provided services to Nevada Power of $15 million, $15 million and $14 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included amounts due to NV Energy of $33 million and $28 million, respectively. There were no receivables due from NV Energy as of December 31, 2021 and 2020. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included receivables due from Sierra Pacific of $2 million. There were no payables due to Sierra Pacific as of December 31, 2021 and 2020.
Nevada Power is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. As of December 31, 2021 and 2020 federal income taxes receivable from NV Energy were $27 million and $— million, respectively. Nevada Power made cash payments of $63 million, $50 million and $113 million for federal income taxes for the years ended December 31, 2021, 2020 and 2019, respectively.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Nevada Power and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2021 was $124 million, an increase of $13 million, or 12%, compared to 2020, primarily due to $5 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, $4 million of higher electric utility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from the residential customer class, partially offset by lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, $4 million of higher other, net, mainly due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies, $3 million of higher allowance for equity funds, mainly due to higher construction work-in-progress, $2 million of higher natural gas utility margin, mainly due to higher commercial usage, and $2 million of lower interest expense, mainly due to lower carrying charges on regulatory balances, partially offset by $3 million of higher income tax expense primarily due to higher pretax income, $2 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant in-service, and $1 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher legal expenses, offset by lower earnings sharing.
Net income for the year ended December 31, 2020 was $111 million, an increase of $8 million, or 8%, compared to 2019, primarily due to $13 million of lower income tax expense due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 1, 2020, $10 million of lower operations and maintenance expenses, primarily due to higher regulatory-directed credits, and $4 million of higher electric utility margin, partially offset by $16 million of higher depreciation and amortization, mainly due to higher plant in-service, and $3 million of lower natural gas utility margin.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Sierra Pacific's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 848 | | | $ | 738 | | | $ | 110 | | 15 | % | | $ | 738 | | | $ | 770 | | | $ | (32) | | (4) | % |
Cost of fuel and energy | | 407 | | | 301 | | | 106 | | 35 | | | 301 | | | 337 | | | (36) | | (11) | |
Electric utility margin | | 441 | | | 437 | | | 4 | | 1 | % | | 437 | | | 433 | | | 4 | | 1 | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 117 | | | 116 | | | 1 | | 1 | % | | 116 | | | 119 | | | (3) | | (3) | % |
Natural gas purchased for resale | | 61 | | | 62 | | | (1) | | (2) | | | 62 | | | 62 | | | — | | — | |
Natural gas utility margin | | 56 | | | 54 | | | 2 | | 4 | % | | 54 | | | 57 | | | (3) | | (5) | % |
| | | | | | | | | | | | | | |
Utility margin | | 497 | | | 491 | | | 6 | | 1 | % | | 491 | | | 490 | | | 1 | | — | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | 163 | | | 162 | | | 1 | | 1 | % | | 162 | | | 172 | | | (10) | | (6) | % |
Depreciation and amortization | | 143 | | | 141 | | | 2 | | 1 | | | 141 | | | 125 | | | 16 | | 13 | |
Property and other taxes | | 24 | | | 23 | | | 1 | | 4 | | | 23 | | | 22 | | | 1 | | 5 | |
Operating income | | $ | 167 | | | $ | 165 | | | $ | 2 | | 1 | % | | $ | 165 | | | $ | 171 | | | $ | (6) | | (4) | % |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 848 | | | $ | 738 | | | $ | 110 | | 15 | % | | $ | 738 | | | $ | 770 | | | $ | (32) | | (4) | % |
Cost of fuel and energy | | 407 | | | 301 | | | 106 | | 35 | | | 301 | | | 337 | | | (36) | | (11) | |
Utility margin | | $ | 441 | | | $ | 437 | | | $ | 4 | | 1 | % | | $ | 437 | | | $ | 433 | | | $ | 4 | | 1 | % |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 2,769 | | | 2,672 | | | 97 | | 4 | % | | 2,672 | | | 2,491 | | | 181 | | 7 | % |
Commercial | | 3,056 | | | 2,977 | | | 79 | | 3 | | | 2,977 | | | 2,973 | | | 4 | | — | |
Industrial | | 3,716 | | | 3,544 | | | 172 | | 5 | | | 3,544 | | | 3,716 | | | (172) | | (5) | |
Other | | 15 | | | 15 | | | — | | — | | | 15 | | | 16 | | | (1) | | (6) | |
Total fully bundled(1) | | 9,556 | | | 9,208 | | | 348 | | 4 | | | 9,208 | | | 9,196 | | | 12 | | — | |
Distribution only service | | 1,639 | | | 1,670 | | | (31) | | (2) | | | 1,670 | | | 1,629 | | | 41 | | 3 | |
Total retail | | 11,195 | | | 10,878 | | | 317 | | 3 | | | 10,878 | | | 10,825 | | | 53 | | — | |
Wholesale | | 656 | | | 548 | | | 108 | | 20 | | | 548 | | | 662 | | | (114) | | (17) | |
Total GWhs sold | | 11,851 | | | 11,426 | | | 425 | | 4 | % | | 11,426 | | | 11,487 | | | (61) | | (1) | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 365 | | | 359 | | | 6 | | 2 | % | | 359 | | | 352 | | | 7 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 81.77 | | | $ | 73.89 | | | $ | 7.88 | | 11 | % | | $ | 73.89 | | | $ | 76.72 | | | $ | (2.83) | | (4) | % |
Wholesale | | $ | 58.14 | | | $ | 52.52 | | | $ | 5.62 | | 11 | % | | $ | 52.52 | | | $ | 48.54 | | | $ | 3.98 | | 8 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 4,494 | | | 4,477 | | | 17 | | — | % | | 4,477 | | | 4,728 | | | (251) | | (5) | % |
Cooling degree days | | 1,366 | | | 1,176 | | | 190 | | 16 | % | | 1,176 | | | 1,107 | | | 69 | | 6 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 4,712 | | | 5,219 | | | (507) | | (10) | % | | 5,219 | | | 4,891 | | | 328 | | 7 | % |
Coal | | 1,220 | | | 855 | | | 365 | | 43 | | | 855 | | | 1,205 | | | (350) | | (29) | |
Renewables(4) | | 31 | | | 37 | | | (6) | | (16) | | | 37 | | | 37 | | | — | | — | |
Total energy generated | | 5,963 | | | 6,111 | | | (148) | | (2) | | | 6,111 | | | 6,133 | | | (22) | | — | |
Energy purchased | | 4,960 | | | 4,753 | | | 207 | | 4 | | | 4,753 | | | 4,466 | | | 287 | | 6 | |
Total | | 10,923 | | | 10,864 | | | 59 | | 1 | % | | 10,864 | | | 10,599 | | | 265 | | 3 | % |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(5): | | | | | | | | | | | | | | |
Energy generated | | $ | 28.84 | | | $ | 20.12 | | | $ | 8.72 | | 43 | % | | $ | 20.12 | | | $ | 26.29 | | | $ | (6.17) | | (23) | % |
Energy purchased | | $ | 47.39 | | | $ | 37.46 | | | $ | 9.93 | | 27 | % | | $ | 37.46 | | | $ | 39.39 | | | $ | (1.93) | | (5) | % |
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 2, 10 and - GWhs of coal and 6, 31 and - GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2021, 2020 and 2019, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) Includes the Fort Churchill Solar Array which was under lease by Sierra Pacific until it was acquired in December 2021.
(5) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 117 | | | $ | 116 | | | $ | 1 | | 1 | % | | $ | 116 | | | $ | 119 | | | $ | (3) | | (3) | % |
Natural gas purchased for resale | | 61 | | | 62 | | | (1) | | (2) | | | 62 | | | 62 | | | — | | — | |
Utility margin | | $ | 56 | | | $ | 54 | | | $ | 2 | | 4 | % | | $ | 54 | | | $ | 57 | | | $ | (3) | | (5) | % |
| | | | | | | | | | | | | | |
Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 10,662 | | | 10,452 | | | 210 | | 2 | % | | 10,452 | | | 11,311 | | | (859) | | (8) | % |
Commercial | | 5,524 | | | 5,148 | | | 376 | | 7 | | | 5,148 | | | 5,783 | | | (635) | | (11) | |
Industrial | | 1,981 | | | 1,826 | | | 155 | | 8 | | | 1,826 | | | 1,971 | | | (145) | | (7) | |
Total retail | | 18,167 | | | 17,426 | | | 741 | | 4 | % | | 17,426 | | | 19,065 | | | (1,639) | | (9) | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 177 | | | 174 | | | 3 | | 2 | % | | 174 | | | 170 | | | 4 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | $ | 6.44 | | | $ | 6.66 | | | $ | (0.22) | | (3) | % | | $ | 6.66 | | | $ | 6.24 | | | $ | 0.42 | | 7 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 4,494 | | | 4,477 | | | 17 | | — | % | | 4,477 | | | 4,728 | | | (251) | | (5) | % |
| | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | $ | 3.36 | | | $ | 3.56 | | | $ | (0.20) | | (6) | % | | $ | 3.56 | | | $ | 3.25 | | | $ | 0.31 | | 9 | % |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Electric utility margin increased $4 million, or 1%, for 2021 compared to 2020 primarily due to:
•$10 million of higher electric retail utility margin primarily due to higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.9% primarily due to an increase in the average number of customers, favorable changes in customer usage patterns and the favorable impact of weather, and
•$3 million of higher transmission and wholesale revenue.
The increase in electric utility margin was offset by:
•$3 million in lower revenue recognized due to a favorable regulatory decision in 2020;
•$3 million due to an adjustment to regulatory-related revenue deferrals; and
•$2 million due to lower energy efficiency program costs (offset in operations and maintenance expense).
Natural gas utility margin increased $2 million, or 4%, for 2021 compared to 2020 primarily due to favorable changes in customer usage patterns.
Operations and maintenance increased $1 million, or 1%, for 2021 compared to 2020 primarily due to higher plant operations and maintenance expenses and higher legal expenses, offset by lower earnings sharing and lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $2 million, or 1%, for 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in-service.
Interest expense decreased $2 million, or 4%, for 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances.
Allowance for equity funds increased$3 million, or 75%, for 2021 compared to 2020 primarily due to higher construction work-in-progress.
Interest and dividend income increased $5 million for 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $4 million, or 57%, for 2021 compared to 2020 primarily due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies.
Income tax expense increased $3 million, or 20%, for 2021 compared to 2020 primarily due to higher pretax income. The effective tax rate was 13% in 2021 and 12% in 2020.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Electric utility margin increased $4 million, or 1%, for 2020 compared to 2019 primarily due to:
•$4 million in higher residential customer volumes from the favorable impact of weather;
•$3 million due to higher energy efficiency program costs (offset in operations and maintenance expense); and
•$2 million of residential customer growth.
The increase in electric utility margin was offset by:
•$4 million of lower transmission and wholesale revenue; and
•$1 million of higher revenue reductions related to customer service agreements.
Natural gas utility margin decreased $3 million, or 5%, for 2020 compared to 2019 primarily due to lower customer volumes mainly from the unfavorable impacts of weather.
Operations and maintenance decreased $10 million, or 6%, for 2020 compared to 2019 primarily due to higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) of $9 million and lower plant operations and maintenance expenses, offset by lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019 and higher energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $16 million, or 13%, for 2020 compared to 2019 primarily due to higher plant placed in-service and higher depreciation expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Other income (expense) is favorable $1 million, or 3%, for 2020 compared to 2019 primarily due to lower pension costs, partially offset by higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Income tax expense decreased $13 million, or 46%, for 2020 compared to 2019. The effective tax rate was 12% in 2020 and 21% in 2019 and decreased due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 1, 2020.
Liquidity and Capital Resources
As of December 31, 2021, Sierra Pacific's total net liquidity was $101 million as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 10 | |
| | |
Credit facilities(1) | | 250 | |
Less - | | |
Short-term debt | | (159) | |
| | |
Net credit facilities | | 91 | |
| | |
Total net liquidity | | $ | 101 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Sierra Pacific's credit facility.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $183 million and $190 million, respectively. The change was primarily due to the timing of payments for fuel and energy costs, partially offset by higher collections from customers, the timing of payments for operating costs, lower inventory purchases and increased collections of customer advances.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $190 million and $237 million, respectively. The change was primarily due to lower collections from customers, higher inventory purchases, the timing of payments for operating costs and higher payments for fuel and energy costs, partially offset by lower payments for income taxes.
The timing of Sierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(300) million and $(246) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $(246) million and $(247) million, respectively. The change was primarily due to decreased capital expenditures, partially offset by expenditures related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the years ended December 31, 2021 and 2020 were $107 million and $50 million, respectively. The change was primarily due to higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the issuance of long-term debt.
Net cash flows from financing activities for the years ended December 31, 2020 and 2019 were $50 million and $(34) million, respectively. The change was primarily due to lower payments to repurchase long-term debt, higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the re-offering of previously repurchased long-term debt.
Ability to Issue Debt
Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2021, Sierra Pacific has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Sierra Pacific's $250 million secured credit facility) does not exceed $1.6 billion as measured at the end of each calendar quarter. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of December 31, 2021. In addition, certain financing agreements contain covenants which are currently suspended as Sierra Pacific's senior secured debt is rated investment grade. However, if Sierra Pacific's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Sierra Pacific would be subject to limitations under these covenants.
In January 2022, the PUCN approved Sierra Pacific's request to increase its financing authority for debt securities to not exceed $1.9 billion as measured at the end of each calendar quarter. Additionally, the PUCN authorized Sierra Pacific to issue common and preferred stock so long as the total amounts outstanding do not exceed $2.2 billion and $500 million, respectively, at the end of each calendar quarter.
Ability to Issue General and Refunding Mortgage Securities
To the extent Sierra Pacific has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Sierra Pacific's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Sierra Pacific's indenture.
Sierra Pacific's indenture creates a lien on substantially all of Sierra Pacific's properties in Nevada. As of December 31, 2021, $4.5 billion of Sierra Pacific's assets were pledged. Sierra Pacific had the capacity to issue $1.7 billion of additional general and refunding mortgage securities as of December 31, 2021 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Sierra Pacific also has the ability to release property from the lien of Sierra Pacific's indenture on the basis of net property additions, cash or retired bonds. To the extent Sierra Pacific releases property from the lien of Sierra Pacific's indenture, it will reduce the amount of securities issuable under the indenture.
Common Shareholder's Equity
In January 2022, Sierra Pacific received a capital contribution of $130 million from NV Energy, Inc.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including Sierra Pacific's credit ratings, investors' judgment of risk associated with Sierra Pacific and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Electric distribution | $ | 156 | | | $ | 128 | | | $ | 96 | | | $ | 122 | | | $ | 129 | | | $ | 112 | |
Electric transmission | 17 | | | 60 | | | 77 | | | 164 | | | 242 | | | 326 | |
Solar generation | — | | | — | | | 17 | | | 1 | | | 134 | | | 197 | |
Other | 72 | | | 58 | | | 110 | | | 160 | | | 100 | | | 74 | |
Total | $ | 245 | | | $ | 246 | | | $ | 300 | | | $ | 447 | | | $ | 605 | | | $ | 709 | |
Sierra Pacific received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its latest IRP filing in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar generation includes growth projects consisting of two solar photovoltaic facilities. The first project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. Both facilities will be jointly owned and operated by Nevada Power and Sierra Pacific.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
Sierra Pacific has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7) and AROs (refer to Note 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Sierra Pacific has cash requirements relating to interest payments of $411 million on long-term debt, including $41 million due in 2022.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Sierra Pacific's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Sierra Pacific is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Sierra Pacific's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Sierra Pacific has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Sierra Pacific's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, Sierra Pacific would have been required to post $18 million of additional collateral. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where Sierra Pacific operates has not had a significant impact on Sierra Pacific's financial results. Sierra Pacific operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Sierra Pacific is allowed to include prudent costs in its rates, including the impact of inflation after Sierra Pacific experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Sierra Pacific attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Sierra Pacific's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Sierra Pacific's Summary of Significant Accounting Policies included in Sierra Pacific's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Sierra Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $440 million and total regulatory liabilities were $463 million as of December 31, 2021. Refer to Sierra Pacific's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Sierra Pacific would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Sierra Pacific's results of operations.
Income Taxes
In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local income tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Sierra Pacific's financial results. Refer to Sierra Pacific's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's income taxes.
It is probable that Sierra Pacific will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to its customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $234 million and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $78 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Sierra Pacific's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Sierra Pacific's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Sierra Pacific transacts. The following discussion addresses the significant market risks associated with Sierra Pacific's business activities. Sierra Pacific has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's contracts accounted for as derivatives.
Commodity Price Risk
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which metmay include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Sierra Pacific's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Sierra Pacific's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | (33) | | | $ | (26) | | | $ | (40) | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | 7 | | | $ | 8 | | | $ | 6 | |
Sierra Pacific's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose Sierra Pacific to earnings volatility. As of December 31, 2021 and 2020, a net regulatory asset of $33 million and net regulatory liability of $7 million, respectively, was recorded related to the net derivative liability of $33 million and net derivative asset of $7 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Sierra Pacific is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Sierra Pacific's fixed-rate long-term debt does not expose Sierra Pacific to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Sierra Pacific were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Sierra Pacific's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Sierra Pacific's short- and long-term debt.
As of December 31, 2021 and 2020, Sierra Pacific had short-term variable-rate obligations totaling $159 million and $45 million, respectively, that expose Sierra Pacific to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Sierra Pacific's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, Sierra Pacific's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sierra Pacific as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Sierra Pacific's management. Our responsibility is to express an opinion on Sierra Pacific's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Sierra Pacific is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Sierra Pacific's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Sierra Pacific is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Sierra Pacific operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense, and income tax expense.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Sierra Pacific an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Sierra Pacific Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Sierra Pacific's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Sierra Pacific's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected Sierra Pacific's filings with the Commissions and the filings with the Commissions by intervenors that may impact Sierra Pacific's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 25, 2022
We have served as Sierra Pacific's auditor since 1996.
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 10 | | | $ | 19 | |
Trade receivables, net | 128 | | | 97 | |
| | | |
Inventories | 65 | | | 77 | |
Regulatory assets | 177 | | | 67 | |
| | | |
Other current assets | 35 | | | 45 | |
Total current assets | 415 | | | 305 | |
| | | |
Property, plant and equipment, net | 3,340 | | | 3,164 | |
Regulatory assets | 263 | | | 267 | |
Other assets | 205 | | | 183 | |
| | | |
Total assets | $ | 4,223 | | | $ | 3,919 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 147 | | | $ | 108 | |
Accrued interest | 14 | | | 14 | |
Accrued property, income and other taxes | 16 | | | 14 | |
Short-term debt | 159 | | | 45 | |
| | | |
Regulatory liabilities | 19 | | | 34 | |
Customer deposits | 15 | | | 15 | |
Other current liabilities | 44 | | | 25 | |
Total current liabilities | 414 | | | 255 | |
| | | |
Long-term debt | 1,164 | | | 1,164 | |
Finance lease obligations | 106 | | | 121 | |
Regulatory liabilities | 444 | | | 463 | |
Deferred income taxes | 402 | | | 374 | |
Other long-term liabilities | 158 | | | 131 | |
Total liabilities | 2,688 | | | 2,508 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | |
Additional paid-in capital | 1,111 | | | 1,111 | |
Retained earnings | 425 | | | 301 | |
Accumulated other comprehensive loss, net | (1) | | | (1) | |
Total shareholder's equity | 1,535 | | | 1,411 | |
| | | |
Total liabilities and shareholder's equity | $ | 4,223 | | | $ | 3,919 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue: | | | | | |
Regulated electric | $ | 848 | | | $ | 738 | | | $ | 770 | |
Regulated natural gas | 117 | | | 116 | | | 119 | |
Total operating revenue | 965 | | | 854 | | | 889 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 407 | | | 301 | | | 337 | |
Cost of natural gas purchased for resale | 61 | | | 62 | | | 62 | |
Operations and maintenance | 163 | | | 162 | | | 172 | |
Depreciation and amortization | 143 | | | 141 | | | 125 | |
Property and other taxes | 24 | | | 23 | | | 22 | |
| | | | | |
Total operating expenses | 798 | | | 689 | | | 718 | |
| | | | | |
Operating income | 167 | | | 165 | | | 171 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (54) | | | (56) | | | (48) | |
Allowance for borrowed funds | 2 | | | 2 | | | 1 | |
Allowance for equity funds | 7 | | | 4 | | | 3 | |
Interest and dividend income | 9 | | | 4 | | | 3 | |
Other, net | 11 | | | 7 | | | 1 | |
Total other income (expense) | (25) | | | (39) | | | (40) | |
| | | | | |
Income before income tax expense | 142 | | | 126 | | | 131 | |
Income tax expense | 18 | | | 15 | | | 28 | |
Net income | $ | 124 | | | $ | 111 | | | $ | 103 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Retained | | Accumulated | | |
| | | | | | Other | | Earnings | | Other | | Total |
| | Common Stock | | Paid-in | | (Accumulated | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Deficit) | | Loss, Net | | Equity |
Balance, December 31, 2018 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 153 | | | $ | — | | | $ | 1,264 | |
Net income | | — | | | — | | | — | | | 103 | | | — | | | 103 | |
Dividends declared | | — | | | — | | | — | | | (46) | | | — | | | (46) | |
Other equity transactions | | — | | | — | | | — | | | — | | | (1) | | | (1) | |
Balance, December 31, 2019 | | 1,000 | | | — | | | 1,111 | | | 210 | | | (1) | | | 1,320 | |
Net income | | — | | | — | | | — | | | 111 | | | — | | | 111 | |
Dividends declared | | — | | | — | | | — | | | (20) | | | — | | | (20) | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | — | | | 1,111 | | | 301 | | | (1) | | | 1,411 | |
Net income | | — | | | — | | | — | | | 124 | | | — | | | 124 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 124 | | | $ | 111 | | | $ | 103 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 143 | | | 141 | | | 125 | |
Allowance for equity funds | (7) | | | (4) | | | (3) | |
Changes in regulatory assets and liabilities | (39) | | | (33) | | | 25 | |
Deferred income taxes and amortization of investment tax credits | 13 | | | 12 | | | 9 | |
Deferred energy | (116) | | | (17) | | | 15 | |
Amortization of deferred energy | 29 | | | (14) | | | (2) | |
Other, net | (1) | | | (2) | | | — | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | (27) | | | (81) | | | (6) | |
Inventories | 12 | | | (19) | | | (5) | |
Accrued property, income and other taxes | 9 | | | 9 | | | (16) | |
Accounts payable and other liabilities | 43 | | | 87 | | | (8) | |
Net cash flows from operating activities | 183 | | | 190 | | | 237 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (300) | | | (246) | | | (248) | |
| | | | | |
Other, net | — | | | — | | | 1 | |
Net cash flows from investing activities | (300) | | | (246) | | | (247) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | 30 | | | 125 | |
Repayments of long-term debt | — | | | — | | | (109) | |
Net proceeds from short-term debt | 114 | | | 45 | | | — | |
Dividends paid | — | | | (20) | | | (46) | |
Other, net | (7) | | | (5) | | | (4) | |
Net cash flows from financing activities | 107 | | | 50 | | | (34) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (10) | | | (6) | | | (44) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 26 | | | 32 | | | 76 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 16 | | | $ | 26 | | | $ | 32 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Presentation
The Consolidated Financial Statements include the accounts of Sierra Pacific and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Sierra Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Sierra Pacific's assessment of the collectability of amounts owed to Sierra Pacific by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Sierra Pacific primarily utilizes credit loss history. However, Sierra Pacific may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Sierra Pacific also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The changes in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 2 | | | $ | 2 | | | $ | 2 | |
Charged to operating costs and expenses, net | 2 | | | 2 | | | 1 | |
Write-offs, net | (3) | | | (2) | | | (1) | |
Ending balance | $ | 1 | | | $ | 2 | | | $ | 2 | |
Derivatives
Sierra Pacific employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Consolidated Statements of Operations.
For Sierra Pacific's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies totaling $62 million and $67 million as of December 31, 2021 and 2020, respectively, and fuel, which includes coal stock, stored natural gas and fuel oil, totaling $3 million and $10 million as of December 31, 2021 and 2020, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Sierra Pacific capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Sierra Pacific's various regulatory authorities. Depreciation studies are completed by Sierra Pacific to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Sierra Pacific retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Sierra Pacific is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Sierra Pacific's AFUDC rate used during 2021 and 2020 was 6.75% for electric, 5.75% for natural gas and 6.65% for common facilities.
Asset Retirement Obligations
Sierra Pacific recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Sierra Pacific's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
Sierra Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the option. Sierra Pacific's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Sierra Pacific's operating and finance right-of-use assets are recorded in other assets and the operating and current finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Income Taxes
Berkshire Hathaway includes Sierra Pacific in its consolidated United States federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that Sierra Pacific deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Sierra Pacific's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Sierra Pacific uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Sierra Pacific expects to be entitled in exchange for those goods or services. Sierra Pacific records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Sierra Pacific's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 842, "Leases" and amounts not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."
Revenue recognized is equal to what Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $78 million and $59 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,163 | | | $ | 1,130 | |
Electric transmission | 50 - 100 years | | 940 | | | 908 | |
Electric distribution | 20 - 100 years | | 1,846 | | | 1,754 | |
Electric general and intangible plant | 5 - 70 years | | 204 | | | 189 | |
Natural gas distribution | 35 - 70 years | | 438 | | | 429 | |
Natural gas general and intangible plant | 5 - 70 years | | 14 | | | 15 | |
Common general | 5 - 70 years | | 370 | | | 355 | |
Utility plant | | | 4,975 | | | 4,780 | |
Accumulated depreciation and amortization | | | (1,854) | | | (1,755) | |
Utility plant, net | | | 3,121 | | | 3,025 | |
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | — | | | 2 | |
Plant, net | | | 3,121 | | | 3,027 | |
Construction work-in-progress | | | 219 | | | 137 | |
Property, plant and equipment, net | | | $ | 3,340 | | | $ | 3,164 | |
All of Sierra Pacific's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Sierra Pacific's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2021, 2020 and 2019 was 3.1%, 3.2% and 3.1%, respectively. Sierra Pacific is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2016.
Construction work-in-progress is primarily related to the construction of regulated assets.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements, Sierra Pacific, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Sierra Pacific accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Sierra Pacific's share of the expenses of these facilities.
The amounts shown in the table below represent Sierra Pacific's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Sierra | | | | | | Construction |
| Pacific's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Valmy Generating Station | 50 | % | | $ | 394 | | | $ | 309 | | | $ | 1 | |
ON Line Transmission Line | 6 | | | 40 | | | 8 | | | — | |
Valmy Transmission | 50 | | | 4 | | | 2 | | | — | |
Total | | | $ | 438 | | | $ | 319 | | | $ | 1 | |
(5) Leases
The following table summarizes Sierra Pacific's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 15 | | | $ | 16 | |
Finance leases | 111 | | | 126 | |
Total right-of-use assets | $ | 126 | | | $ | 142 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 15 | | | $ | 16 | |
Finance leases | 115 | | | 130 | |
Total lease liabilities | $ | 130 | | | $ | 146 | |
The following table summarizes Sierra Pacific's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 86 | | | $ | 78 | | | $ | 69 | |
Operating | 1 | | | 2 | | | 1 | |
Finance: | | | | | |
Amortization | 5 | | | 4 | | | 2 | |
Interest | 9 | | | 9 | | | 2 | |
| | | | | |
Total lease costs | $ | 101 | | | $ | 93 | | | $ | 74 | |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 27.4 | | 27.2 | | 26.3 |
Finance leases | 28.4 | | 27.8 | | 20.9 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 5.0 | % | | 5.0 | % | | 5.0 | % |
Finance leases | 8.2 | % | | 8.1 | % | | 7.1 | % |
The following table summarizes Sierra Pacific's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
Operating cash flows from operating leases | $ | (1) | | | $ | (2) | | | $ | (3) | |
Operating cash flows from finance leases | (9) | | | (6) | | | (3) | |
Financing cash flows from finance leases | (7) | | | (5) | | | (3) | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | |
| | | | | |
Finance leases | $ | 1 | | | $ | 89 | | | $ | 5 | |
Sierra Pacific has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 1 | | | $ | 16 | | | $ | 17 | |
2023 | 1 | | | 16 | | | 17 | |
2024 | 1 | | | 15 | | | 16 | |
2025 | 1 | | | 15 | | | 16 | |
2026 | 1 | | | 15 | | | 16 | |
Thereafter | 24 | | | 149 | | | 173 | |
Total undiscounted lease payments | 29 | | | 226 | | | 255 | |
Less - amounts representing interest | (14) | | | (111) | | | (125) | |
Lease liabilities | $ | 15 | | | $ | 115 | | | $ | 130 | |
Operating and Finance Lease Obligations
Sierra Pacific's operating and finance lease obligations consist mainly of ON Line and Truckee-Carson Irrigation District ("TCID"). ON Line was placed in-service on December 31, 2013. Sierra Pacific and Nevada Power, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the necessary procedures to change the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved ownership percentage change from Nevada Power to Sierra Pacific. The term of the lease criteria for 2018, 2017 and 2016 were $271 million, $310is 41 years with the agreement ending December 31, 2054. In 1999, Sierra Pacific entered into a 50-year agreement with TCID to lease electric distribution facilities. Total finance lease obligations of $110 million and $302$122 million were included on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively, for these leases. See Note 2 for further discussion of Sierra Pacific's remaining lease obligations.
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. Sierra Pacific's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred energy costs | 1 year | | $ | 107 | | | $ | 22 | |
Merger costs from 1999 merger | 25 years | | 66 | | | 68 | |
Natural disaster protection plan | 1 year | | 62 | | | 45 | |
Employee benefit plans(1) | 8 years | | 46 | | | 81 | |
Unrealized loss on regulated derivative contracts | 1 year | | 35 | | | 2 | |
Deferred operating costs | 8 years | | 31 | | | 27 | |
Abandoned projects | 5 years | | 19 | | | 22 | |
| | | | | |
| | | | | |
Other | Various | | 74 | | | 67 | |
Total regulatory assets | | | $ | 440 | | | $ | 334 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 177 | | | $ | 67 | |
Noncurrent assets | | | 263 | | | 267 | |
Total regulatory assets | | | $ | 440 | | | $ | 334 | |
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
Sierra Pacific had regulatory assets not earning a return on investment of $158 million and $149 million as of December 31, 2021 and 2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, a portion of the employee benefit plans, losses on reacquired debt, AROs and legacy meters.
Regulatory Liabilities
Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Sierra Pacific's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 234 | | | $ | 249 | |
Cost of removal(2) | 36 years | | 201 | | | 197 | |
| | | | | |
| | | | | |
Other | Various | | 28 | | | 51 | |
Total regulatory liabilities | | | $ | 463 | | | $ | 497 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 19 | | | $ | 34 | |
Noncurrent liabilities | | | 444 | | | 463 | |
Total regulatory liabilities | | | $ | 463 | | | $ | 497 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Natural Disaster Protection Plan ("NDPP")
In March 2021, Sierra Pacific filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Sierra Pacific filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Sierra Pacific and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")
EEPR was established to allow Sierra Pacific to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Sierra Pacific. When Sierra Pacific's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2021, Sierra Pacific filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2020, including carrying charges. In August 2021, the PUCN issued an order accepting a stipulation requiring Sierra Pacific to refund the 2020 revenue and reset the rates as filed effective October 1, 2021.The EEIR liability for Sierra Pacific is $1 million and $2 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively.
(7)Short-term Debt and Credit Facilities
The following table summarizes Sierra Pacific's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | | | | | | | |
| | 2021 | | 2020 |
Credit facilities | | $ | 250 | | | $ | 250 | |
Short-term debt | | (159) | | | (45) | |
| | | | |
Net credit facilities | | $ | 91 | | | $ | 205 | |
Sierra Pacific has a $250 million secured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long‑term debt securities. As of December 31, 2021 and 2020, Sierra Pacific had borrowings of $159 million and $45 million, respectively, outstanding under the credit facility. As of December 31, 2021 and 2020, the weighted average interest rate on borrowings outstanding was 0.86% and 0.90%, respectively. Amounts due under Sierra Pacific's credit facility are collateralized by Sierra Pacific's general and refunding mortgage bonds. The credit facility requires Sierra Pacific's ratio of debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
(8) Long-term Debt
Sierra Pacific's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
General and refunding mortgage securities: | | | | | |
3.375% Series T, due 2023 | $ | 250 | | | $ | 249 | | | $ | 249 | |
2.600% Series U, due 2026 | 400 | | | 397 | | | 396 | |
6.750% Series P, due 2037 | 252 | | | 253 | | | 255 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
| | | | | |
1.850% Pollution Control Series 2016B, due 2029 (1) | 30 | | | 30 | | | 29 | |
| | | | | |
3.000% Gas and Water Series 2016B, due 2036 (2) | 60 | | | 60 | | | 61 | |
0.625% Water Facilities Series 2016C, due 2036 (1) | 30 | | | 30 | | | 30 | |
2.050% Water Facilities Series 2016D, due 2036 (1) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016E, due 2036 (1) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016F, due 2036 (1) | 75 | | | 75 | | | 74 | |
1.850% Water Facilities Series 2016G, due 2036 (1) | 20 | | | 20 | | | 20 | |
Total long-term debt | $ | 1,167 | | | $ | 1,164 | | | $ | 1,164 | |
| | | | | |
Reflected as - | | | | | |
| | | | | |
Long-term debt | | | $ | 1,164 | | | $ | 1,164 | |
| | | | | |
(1)Subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.
(2)Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt for the years beginning January 1, 2022 and thereafter, are as follows (in millions):
| | | | | |
| |
| |
| |
| |
2023 | $ | 250 | |
| |
| |
2026 | 400 | |
2027 and thereafter | 517 | |
Total | 1,167 | |
Unamortized premium, discount and debt issuance cost | (3) | |
| |
| |
Total | $ | 1,164 | |
The issuance of General and Refunding Mortgage Securities by Sierra Pacific is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2021, approximately $4.5 billion (based on original cost) of Sierra Pacific's property was subject to the liens of the mortgages.
(9) Income Taxes
Income tax expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current – Federal | $ | 5 | | | $ | 3 | | | $ | 19 | |
| | | | | |
Deferred – Federal | 13 | | | 12 | | | 10 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Investment tax credits | — | | | — | | | (1) | |
Total income tax expense | $ | 18 | | | $ | 15 | | | $ | 28 | |
A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (8) | | | (9) | | | — | |
| | | | | |
| | | | | |
| | | | | |
Effective income tax rate | 13 | % | | 12 | % | | 21 | % |
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 64 | | | $ | 67 | |
| | | |
| | | |
Operating and finance leases | 27 | | | 30 | |
Customer advances | 14 | | | 10 | |
Unamortized contract value | 8 | | | 2 | |
Other | 6 | | | 8 | |
Total deferred income tax assets | 119 | | | 117 | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (379) | | | (380) | |
Regulatory assets | (94) | | | (74) | |
Operating and finance leases | (27) | | | (30) | |
Other | (21) | | | (7) | |
Total deferred income tax liabilities | (521) | | | (491) | |
Net deferred income tax liability | $ | (402) | | | $ | (374) | |
| | | |
| | | |
| | | |
| | | |
| | | |
The United States Internal Revenue Service has closed its examination of NV Energy's consolidated income tax returns through December 31, 2008, and effectively settled its examination of Sierra Pacific's income tax return for the short year ended December 31, 2013, and the statute of limitations has expired for NV Energy's consolidated income tax returns through the short year ended December 19, 2013. The closure or effective settlement of examinations, or the expiration of the statute of limitations may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
(10) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific did not make any contributions to the Qualified Pension Plan for the years ended December 31, 2021, 2020 and 2019. Sierra Pacific contributed $1 million to the Non-Qualified Pension Plans for the years ended December 31, 2021, 2020 and 2019. Sierra Pacific contributed $1 million to the Other Post Retirement Plan for the year ended December 31, 2021. Sierra Pacific did not make any contributions to the Other Post Retirement Plans for the years ended December 31, 2020 and 2019. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Qualified Pension Plan - | | | |
Other non-current assets | $ | 62 | | | $ | 26 | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (7) | | | (8) | |
| | | |
Other Postretirement Plans - | | | |
Other long-term liabilities | (10) | | | (13) | |
(11) Asset Retirement Obligations
Sierra Pacific estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Sierra Pacific does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of Operations.removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $201 million and $197 million as of December 31, 2021 and 2020, respectively.
The following table presents Sierra Pacific's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Asbestos | $ | 5 | | | $ | 5 | |
Evaporative ponds and dry ash landfills | 3 | | | 3 | |
Other | 3 | | | 3 | |
Total asset retirement obligations | $ | 11 | | | $ | 11 | |
The following table reconciles the beginning and ending balances of Sierra Pacific's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 11 | | | $ | 10 | |
| | | |
| | | |
| | | |
Accretion | — | | | 1 | |
Ending balance | $ | 11 | | | $ | 11 | |
| | | |
Reflected as - | | | |
| | | |
| | | |
Other long-term liabilities | $ | 11 | | | $ | 11 | |
Certain of Sierra Pacific's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Sierra Pacific is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Sierra Pacific's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)Risk Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 2 | | | | | $ | — | | | $ | — | | | $ | 2 | |
Commodity liabilities | — | | | | | (16) | | | (19) | | | (35) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 2 | | | | | $ | (16) | | | $ | (19) | | | $ | (33) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 9 | | | | | $ | — | | | $ | — | | | $ | 9 | |
Commodity liabilities | — | | | | | — | | | (2) | | | (2) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 9 | | | | | $ | — | | | $ | (2) | | | $ | 7 | |
(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2021 a regulatory asset of $33 million was recorded related to the net derivative liability of $33 million. As of December 31, 2020 a regulatory liability of $7 million was recorded related to the net derivative asset of $7 million.
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases | Megawatt hours | | 1 | | | — | |
Natural gas purchases | Decatherms | | 53 | | | 54 | |
| | | | | |
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $— million as of December 31, 2021 and 2020, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | |
Money market mutual funds | 10 | | | — | | | — | | | 10 | |
Investment funds | 1 | | | — | | | — | | | 1 | |
| $ | 11 | | | $ | — | | | $ | 2 | | | $ | 13 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (35) | | | $ | (35) | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | |
Money market mutual funds | 17 | | | — | | | — | | | 17 | |
| $ | 17 | | | $ | — | | | $ | 9 | | | $ | 26 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of December 31, 2021, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Sierra Pacific's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Beginning balance | | $ | 7 | | | $ | (1) | | | $ | 2 | |
Changes in fair value recognized in regulatory assets or liabilities | | (25) | | | (2) | | | (5) | |
| | | | | | |
Settlements | | (15) | | | 10 | | | 2 | |
Ending balance | | $ | (33) | | | $ | 7 | | | $ | (1) | |
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 1,164 | | | $ | 1,316 | | | $ | 1,164 | | | $ | 1,358 | |
(14) Commitments and Contingencies
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Commitments
Sierra Pacific has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2027 and | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 338 | | | $ | 227 | | | $ | 149 | | | $ | 120 | | | $ | 105 | | | $ | 1,072 | | | $ | 2,011 | |
Fuel and capacity contract commitments (not commercially operable) | 25 | | | 27 | | | 27 | | | 26 | | | 26 | | | 459 | | | 590 | |
Construction commitments | 35 | | | 497 | | | 737 | | | 76 | | | — | | | — | | | 1,345 | |
| | | | | | | | | | | | | |
Easements | 2 | | | 2 | | | 2 | | | 2 | | | 2 | | | 28 | | | 38 | |
Maintenance, service and other contracts | 7 | | | 6 | | | 6 | | | 5 | | | 1 | | | — | | | 25 | |
Total commitments | $ | 407 | | | $ | 759 | | | $ | 921 | | | $ | 229 | | | $ | 134 | | | $ | 1,559 | | | $ | 4,009 | |
Fuel and Capacity Contract Commitments
Purchased Power
Sierra Pacific has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2022 to 2046. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Sierra Pacific's lease commitments.
CoalAbility to Issue General and Refunding Mortgage Securities
To the extent Nevada Power has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Nevada Power's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Nevada Power's indenture.
Nevada Power's indenture creates a lien on substantially all of Nevada Power's properties in Nevada. As of December 31, 2021, $9.4 billion of Nevada Power's assets were pledged. Nevada Power had the capacity to issue $3.7 billion of additional general and refunding mortgage securities as of December 31, 2021, determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Nevada Power also has the ability to release property from the lien of Nevada Power's indenture on the basis of net property additions, cash or retired bonds. To the extent Nevada Power releases property from the lien of Nevada Power's indenture, it will reduce the amount of securities issuable under the indenture.
Long-Term Debt
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
Future Uses of Cash
Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including Nevada Power's credit ratings, investors' judgment of risk associated with Nevada Power and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Electric distribution | $ | 209 | | | $ | 232 | | | $ | 184 | | | $ | 193 | | | $ | 184 | | | $ | 181 | |
Electric transmission | 24 | | | 35 | | | 57 | | | 169 | | | 206 | | | 432 | |
Solar generation | — | | | — | | | 8 | | | 95 | | | 568 | | | 602 | |
Other | 171 | | | 188 | | | 200 | | | 576 | | | 276 | | | 163 | |
Total | $ | 404 | | | $ | 455 | | | $ | 449 | | | $ | 1,033 | | | $ | 1,234 | | | $ | 1,378 | |
Nevada Power received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its IRP filings in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar generation includes growth projects consisting of three solar photovoltaic facilities. The first project is a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The final project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. The facilities located in Humboldt County will be jointly owned and operated by Nevada Power and Sierra Pacific.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
Nevada Power has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7) and AROs (refer to Note 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Nevada Power has cash requirements relating to interest payments of $1.8 billion on long-term debt, including $115 million due in 2022.
Regulatory Matters
Nevada Power is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Nevada Power's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Nevada Power is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Nevada Power's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Nevada Power has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Nevada Power's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, Nevada Power would have been required to post $113 million of additional collateral. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where Nevada Power operates has not had a significant impact on Nevada Power's consolidated financial results. Nevada Power operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Nevada Power is allowed to include prudent costs in its rates, including the impact of inflation after Nevada Power experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Nevada Power attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Nevada Power's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Nevada Power's Summary of Significant Accounting Policies included in Nevada Power's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $1 billion and total regulatory liabilities were $1.1 billion as of December 31, 2021. Refer to Nevada Power's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Nevada Power would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Nevada Power's results of operations.
Income Taxes
In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Nevada Power's federal, state and local income tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Nevada Power's consolidated financial results. Refer to Nevada Power's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's income taxes.
It is probable that Nevada Power will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property related basis differences and other various differences on to its customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $603 million and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $107 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Nevada Power's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Nevada Power's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Nevada Power transacts. The following discussion addresses the significant market risks associated with Nevada Power's business activities. Nevada Power has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's contracts accounted for as derivatives.
Commodity Price Risk
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity and natural gas market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Nevada Power's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Nevada Power's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | (113) | | | $ | (93) | | | $ | (133) | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | 15 | | | $ | 19 | | | $ | 11 | |
Nevada Power's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose Nevada Power to earnings volatility. As of December 31, 2021 and 2020, a net regulatory asset of $113 million and a net regulatory liability of $15 million, respectively, was recorded related to the net derivative liability of $113 million and net derivative asset of $15 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Nevada Power is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Nevada Power's fixed-rate long-term debt does not expose Nevada Power to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Nevada Power were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Nevada Power's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Nevada Power's short- and long-term debt.
As of December 31, 2021 and 2020, Nevada Power had short-term variable-rate obligations totaling $180 million and $— million, respectively, that expose Nevada Power to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Nevada Power's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, Nevada Power's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries ("Nevada Power") as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Nevada Power as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Nevada Power's management. Our responsibility is to express an opinion on Nevada Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Nevada Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Nevada Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Nevada Power is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Nevada Power operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense, and income tax expense.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Nevada Power an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Nevada Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Nevada Power's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Nevada Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected Nevada Power's filings with the Commissions and the filings with the Commissions by intervenors that may impact Nevada Power's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 25, 2022
We have served as Nevada Power's auditor since 1987.
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 33 | | | $ | 25 | |
Trade receivables, net | 227 | | | 234 | |
Inventories | 64 | | | 69 | |
Derivative contracts | 4 | | | 26 | |
Regulatory assets | 291 | | | 48 | |
| | | |
Prepayments | 33 | | | 38 | |
Other current assets | 49 | | | 26 | |
Total current assets | 701 | | | 466 | |
| | | |
Property, plant and equipment, net | 6,891 | | | 6,701 | |
Finance lease right of use assets, net | 326 | | | 351 | |
Regulatory assets | 728 | | | 746 | |
Other assets | 106 | | | 72 | |
| | | |
Total assets | $ | 8,752 | | | $ | 8,336 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 242 | | | $ | 181 | |
Accrued interest | 32 | | | 32 | |
Accrued property, income and other taxes | 29 | | | 25 | |
Short-term debt | 180 | | | — | |
| | | |
Current portion of finance lease obligations | 26 | | | 27 | |
Regulatory liabilities | 49 | | | 50 | |
Customer deposits | 44 | | | 47 | |
Asset retirement obligation | 19 | | | 25 | |
Derivative contracts | 55 | | | 4 | |
Other current liabilities | 17 | | | 18 | |
Total current liabilities | 693 | | | 409 | |
| | | |
Long-term debt | 2,499 | | | 2,496 | |
Finance lease obligations | 310 | | | 334 | |
Regulatory liabilities | 1,100 | | | 1,163 | |
Deferred income taxes | 782 | | | 738 | |
Other long-term liabilities | 338 | | | 257 | |
Total liabilities | 5,722 | | | 5,397 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding | — | | | — | |
Additional paid-in capital | 2,308 | | | 2,308 | |
Retained earnings | 724 | | | 634 | |
Accumulated other comprehensive loss, net | (2) | | | (3) | |
Total shareholder's equity | 3,030 | | | 2,939 | |
| | | |
Total liabilities and shareholder's equity | $ | 8,752 | | | $ | 8,336 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue | $ | 2,139 | | | $ | 1,998 | | | $ | 2,148 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 939 | | | 816 | | | 943 | |
Operations and maintenance | 301 | | | 299 | | | 324 | |
Depreciation and amortization | 406 | | | 361 | | | 357 | |
Property and other taxes | 48 | | | 47 | | | 45 | |
| | | | | |
Total operating expenses | 1,694 | | | 1,523 | | | 1,669 | |
| | | | | |
Operating income | 445 | | | 475 | | | 479 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (153) | | | (162) | | | (171) | |
Allowance for borrowed funds | 3 | | | 3 | | | 3 | |
Allowance for equity funds | 7 | | | 7 | | | 5 | |
Interest and dividend income | 20 | | | 10 | | | 13 | |
Other, net | 18 | | | 9 | | | 8 | |
Total other income (expense) | (105) | | | (133) | | | (142) | |
| | | | | |
Income before income tax expense | 340 | | | 342 | | | 337 | |
Income tax expense | 37 | | | 47 | | | 73 | |
Net income | $ | 303 | | | $ | 295 | | | $ | 264 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Other | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2018 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 600 | | | $ | (4) | | | $ | 2,904 | |
Net income | | — | | | — | | | — | | | 264 | | | — | | | 264 | |
Dividends declared | | — | | | — | | | — | | | (371) | | | — | | | (371) | |
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 | | | — | | | 2,308 | | | 493 | | | (4) | | | 2,797 | |
Net income | | — | | | — | | | — | | | 295 | | | — | | | 295 | |
Dividends declared | | — | | | — | | | — | | | (155) | | | — | | | (155) | |
Other equity transactions | | — | | | — | | | — | | | 1 | | | 1 | | | 2 | |
Balance, December 31, 2020 | | 1,000 | | | — | | | 2,308 | | | 634 | | | (3) | | | 2,939 | |
Net income | | — | | | — | | | — | | | 303 | | | — | | | 303 | |
Dividends declared | | — | | | — | | | — | | | (213) | | | — | | | (213) | |
Other equity transactions | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 303 | | | $ | 295 | | | $ | 264 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 406 | | | 361 | | | 357 | |
Allowance for equity funds | (7) | | | (7) | | | (5) | |
Changes in regulatory assets and liabilities | (19) | | | (42) | | | 27 | |
Deferred income taxes and amortization of investment tax credits | — | | | (10) | | | (32) | |
Deferred energy | (245) | | | (44) | | | 51 | |
Amortization of deferred energy | 11 | | | (41) | | | 43 | |
Other, net | — | | | 2 | | | (5) | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | 6 | | | 45 | | | 19 | |
Inventories | 5 | | | (7) | | | 1 | |
Accrued property, income and other taxes | (18) | | | 5 | | | (13) | |
Accounts payable and other liabilities | 63 | | | (90) | | | (6) | |
Net cash flows from operating activities | 505 | | | 467 | | | 701 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (449) | | | (455) | | | (409) | |
| | | | | |
Proceeds from sale of assets | — | | | 26 | | | 2 | |
Other, net | 2 | | | — | | | — | |
Net cash flows from investing activities | (447) | | | (429) | | | (407) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | 718 | | | 495 | |
Repayments of long-term debt | — | | | (575) | | | (500) | |
Net proceeds from short-term debt | 180 | | | — | | | — | |
Dividends paid | (213) | | | (155) | | | (371) | |
Other, net | (16) | | | (15) | | | (14) | |
Net cash flows from financing activities | (49) | | | (27) | | | (390) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 9 | | | 11 | | | (96) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 36 | | | 25 | | | 121 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 45 | | | $ | 36 | | | $ | 25 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Nevada Power Company and its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Nevada Power and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Nevada Power's assessment of the collectability of amounts owed to Nevada Power by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Nevada Power primarily utilizes credit loss history. However, Nevada Power may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Nevada Power also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The changes in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 19 | | | $ | 15 | | | $ | 16 | |
Charged to operating costs and expenses, net | 13 | | | 13 | | | 12 | |
Write-offs, net | (14) | | | (9) | | | (13) | |
Ending balance | $ | 18 | | | $ | 19 | | | $ | 15 | |
Derivatives
Nevada Power employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.
For Nevada Power's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies totaling $64 million and $69 million as of December 31, 2021 and 2020. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Nevada Power capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the Public Utilities Commission of Nevada ("PUCN").
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Nevada Power's various regulatory authorities. Depreciation studies are completed by Nevada Power to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Nevada Power retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Nevada Power is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Nevada Power's AFUDC rate used during 2021 and 2020 was 7.14% and 7.43%, respectively.
Asset Retirement Obligations
Nevada Power recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Nevada Power's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
Nevada Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Nevada Power's operating and right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly.
Income Taxes
Berkshire Hathaway includes Nevada Power in its consolidated United States federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property‑related basis differences and other various differences that Nevada Power deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Nevada Power's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Nevada Power uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Nevada Power expects to be entitled in exchange for those goods or services. Nevada Power records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Nevada Power's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of amounts not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers" and revenue recognized in accordance with ASC 842, "Leases."
Revenue recognized is equal to what Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $107 million and $104 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In addition, Nevada Power has recognized contract assets of $6 million and $8 million as of December 31, 2021 and 2020, respectively, due to Nevada Power's performance on certain contracts.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.
Segment Information
Nevada Power currently has 1 segment, which includes its regulated electric utility operations.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,793 | | | $ | 3,690 | |
Transmission | 45 - 70 years | | 1,503 | | | 1,468 | |
Distribution | 20 - 65 years | | 3,920 | | | 3,771 | |
General and intangible plant | 5 - 65 years | | 836 | | | 791 | |
Utility plant | | | 10,052 | | | 9,720 | |
Accumulated depreciation and amortization | | | (3,406) | | | (3,162) | |
Utility plant, net | | | 6,646 | | | 6,558 | |
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
Plant, net | | | 6,647 | | | 6,559 | |
Construction work-in-progress | | | 244 | | | 142 | |
Property, plant and equipment, net | | | $ | 6,891 | | | $ | 6,701 | |
Almost all of Nevada Power's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Nevada Power's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2021, 2020 and 2019 was 3.2%, 3.1%, and 3.3%, respectively. Nevada Power is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2017.
Construction work-in-progress is primarily related to the construction of regulated assets.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements, Nevada Power, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Nevada Power accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Nevada Power's share of the expenses of these facilities.
The amounts shown in the table below represent Nevada Power's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Nevada | | | | | | Construction |
| Power's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Navajo Generating Station(1) | 11 | % | | $ | 5 | | | $ | 5 | | | $ | — | |
ON Line Transmission Line | 19 | | | 120 | | | 23 | | | 1 | |
Other transmission facilities | Various | | 61 | | | 32 | | | — | |
Total | | | $ | 186 | | | $ | 60 | | | $ | 1 | |
(1)Represents Nevada Power's proportionate share of capitalized asset retirement costs to retire the Navajo Generating Station, which was shut down in November 2019.
(5) Leases
The following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 10 | | | $ | 12 | |
Finance leases | 326 | | | 351 | |
Total right-of-use assets | $ | 336 | | | $ | 363 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 13 | | | $ | 15 | |
Finance leases | 336 | | | 361 | |
Total lease liabilities | $ | 349 | | | $ | 376 | |
The following table summarizes Nevada Power's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 | | |
| | | | | | | |
Variable | $ | 449 | | | $ | 434 | | | $ | 434 | | | |
Operating | 2 | | | 3 | | | 3 | | | |
Finance: | | | | | | | |
Amortization | 13 | | | 12 | | | 13 | | | |
Interest | 28 | | | 29 | | | 37 | | | |
| | | | | | | |
Total lease costs | $ | 492 | | | $ | 478 | | | $ | 487 | | | |
| | | | | | | |
Weighted-average remaining lease term (years): | | | | | | | |
Operating leases | 5.7 | | 6.5 | | 7.5 | | |
Finance leases | 28.7 | | 28.7 | | 30.6 | | |
| | | | | | | |
Weighted-average discount rate: | | | | | | | |
Operating leases | 4.5 | % | | 4.5 | % | | 4.5 | % | | |
Finance leases | 8.6 | % | | 8.6 | % | | 8.7 | % | | |
The following table summarizes Nevada Power's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 | | |
| | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | |
Operating cash flows from operating leases | $ | (3) | | | $ | (3) | | | $ | (3) | | | |
Operating cash flows from finance leases | (29) | | | (34) | | | (37) | | | |
Financing cash flows from finance leases | (16) | | | (15) | | | (14) | | | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | | | |
Operating leases | $ | — | | | $ | 1 | | | $ | — | | | |
Finance leases | 1 | | | 9 | | | 9 | | | |
Nevada Power has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 3 | | | $ | 54 | | | $ | 57 | |
2023 | 2 | | | 44 | | | 46 | |
2024 | 3 | | | 44 | | | 47 | |
2025 | 2 | | | 43 | | | 45 | |
2026 | 3 | | | 43 | | | 46 | |
Thereafter | 2 | | | 448 | | | 450 | |
Total undiscounted lease payments | 15 | | | 676 | | | 691 | |
Less - amounts representing interest | (2) | | | (340) | | | (342) | |
Lease liabilities | $ | 13 | | | $ | 336 | | | $ | 349 | |
Operating and Finance Lease Obligations
Nevada Power's lease obligation primarily consists of a transmission line, One Nevada Transmission Line ("ON Line"), which was placed in-service on December 31, 2013. Nevada Power and Sierra Pacific, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the necessary procedures to change the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved ownership percentage change from Nevada Power to Sierra Pacific. The term of the lease is 41 years with the agreement ending December 31, 2054. Total ON Line finance lease obligations of $286 million and $295 million were included on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. See Note 2 for further discussion of Nevada Power's other lease obligations.
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. Nevada Power's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred energy costs | 1 year | | $ | 273 | | | $ | 39 | |
Decommissioning costs | 2 years | | 169 | | | 230 | |
Unrealized loss on regulated derivative contracts | 1 year | | 117 | | | 11 | |
Merger costs from 1999 merger | 23 years | | 110 | | | 115 | |
Deferred operating costs | 12 years | | 93 | | | 119 | |
Asset retirement obligations | 6 years | | 73 | | | 70 | |
ON Line deferrals | 32 years | | 42 | | | 43 | |
Legacy meters | 11 years | | 41 | | | 45 | |
Employee benefit plans(1) | 8 years | | 11 | | | 50 | |
| | | | | |
Other | Various | | 90 | | | 72 | |
Total regulatory assets | | | $ | 1,019 | | | $ | 794 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 291 | | | $ | 48 | |
Noncurrent assets | | | 728 | | | 746 | |
Total regulatory assets | | | $ | 1,019 | | | $ | 794 | |
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
Nevada Power had regulatory assets not earning a return on investment of $371 million and $288 million as of December 31, 2021 and 2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, AROs, deferred operating costs, a portion of the employee benefit plans, losses on reacquired debt and deferred energy costs.
Regulatory Liabilities
Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Nevada Power's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 603 | | | $ | 647 | |
Cost of removal(2) | 31 years | | 348 | | | 340 | |
| | | | | |
| | | | | |
| | | | | |
Other | Various | | 198 | | | 226 | |
Total regulatory liabilities | | | $ | 1,149 | | | $ | 1,213 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 49 | | | $ | 50 | |
Noncurrent liabilities | | | 1,100 | | | 1,163 | |
Total regulatory liabilities | | | $ | 1,149 | | | $ | 1,213 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Natural GasDisaster Protection Plan ("NDPP")
In March 2021, Nevada Power filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Nevada Power filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Nevada Power and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
Regulatory Rate Review
In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2020, the PUCN issued a final order directing Nevada Power to continue the earning sharing mechanism subject to any modifications made to the earning sharing mechanism pursuant to an alternative rate-making ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory rate review. The new rates were effective on January 1, 2021.
Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")
EEPR was established to allow Nevada Power to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Nevada Power and approved by the PUCN in integrated resource plan proceedings. When Nevada Power's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2021, Nevada Power filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2020, including carrying charges. In August 2021, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 2020 revenue and reset the rates as filed effective October 1, 2021. The EEIR liability for Nevada Power is $8 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020.
(7)Short-term Debt and Credit Facilities
The following table summarizes Nevada Power's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | | | | | | | |
| | 2021 | | 2020 |
Credit facilities | | $ | 400 | | | $ | 400 | |
Short-term debt | | (180) | | | — | |
| | | | |
Net credit facilities | | $ | 220 | | | $ | 400 | |
Nevada Power has a contract$400 million secured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which is for general corporate purposes and provide for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long‑term debt securities. As of December 31, 2021 and 2020, Nevada Power had borrowings of $180 million and $— million, respectively, outstanding under the credit facility. As of December 31, 2021, the weighted average interest rate on borrowings outstanding was 0.86%. Amounts due under Nevada Power's credit facility are collateralized by Nevada Power's general and refunding mortgage bonds. The credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2021, Nevada Power had $15 million of a fully available letter of credit issued under committed arrangements in support of certain transactions required by a third party and has provisions that automatically extend the annual expiration date for an additional year unless the issuing bank elects not to renew the letter of credit prior to the expiration date.
(8) Long-term Debt
Nevada Power's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
General and refunding mortgage securities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
3.700% Series CC, due 2029 | $ | 500 | | | $ | 497 | | | $ | 496 | |
2.400% Series DD, due 2030 | 425 | | | 422 | | | 422 | |
6.650% Series N, due 2036 | 367 | | | 359 | | | 359 | |
6.750% Series R, due 2037 | 349 | | | 346 | | | 346 | |
5.375% Series X, due 2040 | 250 | | | 248 | | | 248 | |
5.450% Series Y, due 2041 | 250 | | | 239 | | | 237 | |
3.125% Series EE, due 2050 | 300 | | | 297 | | | 297 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.875% Pollution Control Bonds Series 2017A, due 2032(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017, due 2036(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017B, due 2039(1) | 13 | | | 13 | | | 13 | |
| | | | | |
| | | | | |
| | | | | |
Total long-term debt | $ | 2,534 | | | $ | 2,499 | | | $ | 2,496 | |
| | | | | |
Reflected as: | | | | | |
| | | | | |
| | | | | |
Total long-term debt | | | $ | 2,499 | | | $ | 2,496 | |
(1)Subject to mandatory purchase by Nevada Power in March 2023 at which date the interest rate may be adjusted.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt for the years beginning January 1, 2022 and thereafter, are as follows (in millions):
| | | | | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
2027 and thereafter | $ | 2,534 | | | | | |
| | | | | |
Unamortized premium, discount and debt issuance cost | (35) | | | | | |
| | | | | |
| | | | | |
Total | $ | 2,499 | | | | | |
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
The issuance of General and Refunding Mortgage Securities by Nevada Power is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2021, approximately $9.4 billion (based on original cost) of Nevada Power's property was subject to the liens of the mortgages.
(9) Income Taxes
Income tax expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current – Federal | $ | 37 | | | $ | 57 | | | $ | 105 | |
| | | | | |
Deferred – Federal | — | | | (10) | | | (31) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Investment tax credits | — | | | — | | | (1) | |
Total income tax expense | $ | 37 | | | $ | 47 | | | $ | 73 | |
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (11) | | | (8) | | | — | |
| | | | | |
| | | | | |
Other | 1 | | | 1 | | | 1 | |
Effective income tax rate | 11 | % | | 14 | % | | 22 | % |
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 195 | | | $ | 206 | |
Operating and finance leases | 73 | | | 79 | |
Customer advances | 25 | | | 19 | |
Unamortized contract value | 25 | | | 8 | |
Other | 8 | | | 15 | |
Total deferred income tax assets | 326 | | | 327 | |
| | | |
| | | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (800) | | | (800) | |
Regulatory assets | (204) | | | (176) | |
Operating and finance leases | (70) | | | (76) | |
Other | (34) | | | (13) | |
Total deferred income tax liabilities | (1,108) | | | (1,065) | |
Net deferred income tax liability | $ | (782) | | | $ | (738) | |
| | | |
| | | |
| | | |
| | | |
| | | |
The United States Internal Revenue Service has closed its examination of NV Energy's consolidated income tax returns through December 31, 2008, and effectively settled its examination of Nevada Power's income tax return for the short year ended December 31, 2013, and the statute of limitations has expired for NV Energy's consolidated income tax returns through the short year ended December 19, 2013. The closure or effective settlement of examinations, or the expiration of the statute of limitations may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
(10) Employee Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power did not make any contributions to the Qualified Pension Plan for the years ended December 31, 2021, 2020 and 2019. Nevada Power contributed $1 million to the Non-Qualified Pension Plans for the years ended December 31, 2021, 2020 and 2019. Nevada Power did not make any contributions to the Other Postretirement Plans for the years ended December 31, 2021, 2020 and 2019. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Qualified Pension Plan - | | | |
Other non-current assets | $ | 42 | | | $ | 8 | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (8) | | | (9) | |
| | | |
Other Postretirement Plans - | | | |
Other non-current assets | 8 | | | 4 | |
| | | |
(11) Asset Retirement Obligations
Nevada Power estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Nevada Power does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $348 million and $340 million as of December 31, 2021 and 2020, respectively.
The following table presents Nevada Power's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Waste water remediation | $ | 37 | | | $ | 36 | |
Evaporative ponds and dry ash landfills | 13 | | | 13 | |
| | | |
Solar | 3 | | | 3 | |
Other | 15 | | | 20 | |
Total asset retirement obligations | $ | 68 | | | $ | 72 | |
The following table reconciles the beginning and ending balances of Nevada Power's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 72 | | | $ | 74 | |
Change in estimated costs | — | | | 9 | |
| | | |
Retirements | (6) | | | (14) | |
Accretion | 2 | | | 3 | |
Ending balance | $ | 68 | | | $ | 72 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 19 | | | $ | 25 | |
Other long-term liabilities | 49 | | | 47 | |
| $ | 68 | | | $ | 72 | |
In 2008, Nevada Power signed an administrative order of consent as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the administrative order of consent, Nevada Power recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between Nevada Power and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station Unit No. 4, Nevada Power and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities as required under the administrative order of consent.
Certain of Nevada Power's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Nevada Power is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Management has identified legal obligations to retire generation plant assets specified in land leases for Nevada Power's jointly-owned Navajo Generating Station, retired in November 2019, and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Nevada Power's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 4 | | | | | $ | — | | | $ | — | | | $ | 4 | |
Commodity liabilities | — | | | | | (55) | | | (62) | | | (117) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 4 | | | | | $ | (55) | | | $ | (62) | | | $ | (113) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 26 | | | | | $ | — | | | $ | — | | | $ | 26 | |
Commodity liabilities | — | | | | | (3) | | | (8) | | | (11) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 26 | | | | | $ | (3) | | | $ | (8) | | | $ | 15 | |
(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2021 a regulatory asset of $113 million was recorded related to the net derivative liability of $113 million. As of December 31, 2020 a regulatory liability of $15 million was recorded related to the net derivative asset of $15 million.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases | Megawatt hours | | 1 | | | 1 | |
Natural gas purchases | Decatherms | | 119 | | | 124 | |
| | | | | |
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $6 million and $3 million as of December 31, 2021 and 2020, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) Fair Value Measurements
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
The following table presents Nevada Power's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
Money market mutual funds | 34 | | | — | | | — | | | 34 | |
Investment funds | 3 | | | — | | | — | | | 3 | |
| $ | 37 | | | $ | — | | | $ | 4 | | | $ | 41 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (117) | | | $ | (117) | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 26 | | | $ | 26 | |
Money market mutual funds | 21 | | | — | | | — | | | 21 | |
Investment funds | 2 | | | — | | | — | | | 2 | |
| $ | 23 | | | $ | — | | | $ | 26 | | | $ | 49 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (11) | | | $ | (11) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of December 31, 2021, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.
Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Nevada Power's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Beginning balance | | $ | 15 | | | $ | (8) | | | $ | 3 | |
Changes in fair value recognized in regulatory assets or liabilities | | (90) | | | (17) | | | (21) | |
| | | | | | |
Settlements | | (38) | | | 40 | | | 10 | |
Ending balance | | $ | (113) | | | $ | 15 | | | $ | (8) | |
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The following table presents the carrying value and estimated fair value of Nevada Power's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,499 | | | $ | 3,067 | | | $ | 2,496 | | | $ | 3,245 | |
(14) Commitments and Contingencies
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Senate Bill 123
In June 2013, the Nevada State Legislature passed Senate Bill 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable facilities and other generating facilities. In May 2014, Nevada Power filed its Emissions Reduction and Capacity Replacement Plan ("ERCR Plan") in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.
In compliance with SB 123, Nevada Power retired 255 MWs of coal-fueled generation in 2019 in addition to the 557 MWs of coal-fueled generation retired in 2017. Consistent with the ERCR Plan, between 2014 and 2016, Nevada Power acquired 536 MWs of natural gas generating resources, executed long-term power purchase agreements for 200 MWs of nameplate renewable energy capacity and constructed a 15-MW solar photovoltaic facility. Nevada Power has the option to acquire 35 MWs of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval.
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that extends through 2019. Additionally,such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Commitments
Nevada Power has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 713 | | | $ | 458 | | | $ | 346 | | | $ | 348 | | | $ | 352 | | | $ | 3,250 | | | $ | 5,467 | |
Fuel and capacity contract commitments (not commercially operable) | 20 | | | 60 | | | 181 | | | 212 | | | 211 | | | 4,302 | | | 4,986 | |
Construction commitments | 141 | | | 209 | | | — | | | — | | | — | | | — | | | 350 | |
Easements | 4 | | | 5 | | | 2 | | | 2 | | | 2 | | | 52 | | | 67 | |
Maintenance, service and other contracts | 51 | | | 34 | | | 23 | | | 18 | | | 14 | | | 33 | | | 173 | |
Total commitments | $ | 929 | | | $ | 766 | | | $ | 552 | | | $ | 580 | | | $ | 579 | | | $ | 7,637 | | | $ | 11,043 | |
Fuel and Capacity Contract Commitments
Purchased Power
Nevada Power has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2026 to 2067. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Nevada Power's lease commitments.
Natural Gas
Nevada Power's gas transportation contracts expire from 2022 to 20322039 and the gas supply contracts expires from 20192022 to 2020.2023.
Fuel and Capacity Contract Commitments - Not Commercially Operable
Nevada Power has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Operating LeasesConstruction Commitments
Nevada Power's construction commitments included in the table above relate to firm commitments and include costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada and certain other generating plant projects.
Easements
Nevada Power has non-cancelable operating leases primarily for office equipment, office space, certain operating facilities, vehicles and land. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power also has non-cancelable easements for land. Operations and maintenance expense on non-cancelable operating leases and easements totaled $7$4 million, $9$4 million and $13$7 million for the years ended December 31, 2018, 20172021, 2020 and 2016,2019, respectively.
Maintenance, Service and Other Contracts
Nevada Power has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 20192022 to 2026.2031.
(13)(15) Revenues from Contracts with Customers
The following table summarizes Nevada Power's revenueCustomer Revenue by customer class for the yearyears ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Retail: | | | | | |
Residential | $ | 1,207 | | | $ | 1,145 | | | $ | 1,141 | |
Commercial | 414 | | | 384 | | | 441 | |
Industrial | 386 | | | 345 | | | 433 | |
Other | 14 | | | 12 | | | 20 | |
Total fully bundled | 2,021 | | | 1,886 | | | 2,035 | |
Distribution only service | 22 | | | 24 | | | 31 | |
Total retail | 2,043 | | | 1,910 | | | 2,066 | |
Wholesale, transmission and other | 74 | | | 62 | | | 57 | |
Total Customer Revenue | 2,117 | | | 1,972 | | | 2,123 | |
Other revenue | 22 | | | 26 | | | 25 | |
Total revenue | $ | 2,139 | | | $ | 1,998 | | | $ | 2,148 | |
|
| | | |
| 2018 |
Customer Revenue: | |
Retail: | |
Residential | $ | 1,195 |
|
Commercial | 433 |
|
Industrial | 425 |
|
Other | 24 |
|
Total fully bundled | 2,077 |
|
Distribution only service | 30 |
|
Total retail | 2,107 |
|
Wholesale, transmission and other | 53 |
|
Total Customer Revenue | 2,160 |
|
Other revenue | 24 |
|
Total revenue | $ | 2,184 |
|
Contract Assets and Liabilities
In the event one of the parties to a contract has performed before the other, Nevada Power would recognize a contract asset or contract liability depending on the relationship between Nevada Power's performance and the customer's payment. As of December 31, 2018 and December 31, 2017, there were no contract assets or contract liabilities recorded on the Consolidated Balance Sheets.
| |
(14) | Related Party Transactions
|
Nevada Power has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Nevada Power under this agreement totaled $2 million for the years ended December 31, 2018, 2017 and 2016.
Kern River Gas Transmission Company, an indirect subsidiary of BHE, provided natural gas transportation and other services to Nevada Power of $58 million, $66 million and $68 million for the years ended December 31, 2018, 2017 and 2016. As of December 31, 2018 and 2017, Nevada Power's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $4 million and $5 million, respectively.
Nevada Power provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $3 million, $3 million and $2 million for the years ended December 31, 2018, 2017 and 2016, respectively. Receivables associated with these services were $- million as of December 31, 2018 and 2017. PacifiCorp provided electricity and the sale of renewable energy credits to Nevada Power of $- million for the years ended December 31, 2018, 2017 and 2016. Payables associated with these transactions were $- million as of December 31, 2018 and 2017.
Nevada Power provided electricity to Sierra Pacific of $91 million, $104 million and $78 million for the years ended December 31, 2018, 2017 and 2016, respectively. Receivables associated with these transactions were $6 million and $10 million as of December 31, 2018 and 2017, respectively. Nevada Power purchased electricity from Sierra Pacific of $28 million, $21 million and $17 million for the years ended December 31, 2018, 2017 and 2016, respectively. Payables associated with these transactions were $1 million and $- million as of December 31, 2018 and 2017, respectively.
Nevada Power incurs intercompany administrative and shared facility costs with NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. Nevada Power provided services to NV Energy of $1 million, $- million and $1 million for each of the years ending December 31, 2018, 2017 and 2016, respectively. NV Energy provided services to Nevada Power of $7 million, $10 million and $10 million for the years ending December 31, 2018, 2017 and 2016, respectively. Nevada Power provided services to Sierra Pacific of $28 million, $27 million and $24 million for the years ended December 31, 2018, 2017 and 2016, respectively. Sierra Pacific provided services to Nevada Power of $15 million, $17 million and $14 million for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, Nevada Power's Consolidated Balance Sheets included amounts due to NV Energy of $26 million and $29 million, respectively. There were no receivables due from NV Energy as of December 31, 2018 and 2017. As of December 31, 2018 and 2017, Nevada Power's Consolidated Balance Sheets included receivables due from Sierra Pacific of $5 million. There were no payables due to Sierra Pacific as of December 31, 2018 and 2017.
Nevada Power is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. Federal income taxes payable to NV Energy were $4 million and $38 million as of December 31, 2018 and 2017, respectively. Nevada Power made cash payments of $117 million, $89 million and $- million for federal income taxes for the years ended December 31, 2018, 2017 and 2016, respectively.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Nevada Power and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
(15)(16) Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 20182021 and December 31, 2017,2020, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN")PUCN for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 20182021 and December 31, 2017,2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| December 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 33 | | | $ | 25 | |
Restricted cash and cash equivalents included in other current assets | 12 | | | 11 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 45 | | | $ | 36 | |
|
| | | | | | | |
| As of |
| December 31, |
| December 31, |
| 2018 |
| 2017 |
Cash and cash equivalents | $ | 111 |
| | $ | 57 |
|
Restricted cash and cash equivalents included in other current assets | 10 |
| | 9 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 121 |
| | $ | 66 |
|
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 115 | | | $ | 115 | | | $ | 126 | |
Income taxes paid | $ | 63 | | | $ | 50 | | | $ | 113 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 53 | | | $ | 32 | | | $ | 49 | |
(17) Related Party Transactions
Nevada Power has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Nevada Power under this agreement totaled $3 million, $2 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Kern River Gas Transmission Company, an indirect subsidiary of BHE, provided natural gas transportation and other services to Nevada Power of $52 million for the years ended December 31, 2021, 2020 and 2019. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $4 million.
Nevada Power provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $3 million, $3 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively. There were no receivables associated with these services as of December 31, 2021 and 2020. PacifiCorp provided electricity and the sale of renewable energy credits to Nevada Power of $— million, $1 million and $— million for the years ended December 31, 2021, 2020, and 2019, respectively. There were no payables associated with these transactions as of December 31, 2021 and 2020.
Nevada Power provided electricity to Sierra Pacific of $179 million, $106 million and $84 million for the years ended December 31, 2021, 2020 and 2019, respectively. Receivables associated with these transactions were $13 million as of December 31, 2021 and 2020. Nevada Power purchased electricity from Sierra Pacific of $43 million, $34 million and $25 million for the years ended December 31, 2021, 2020 and 2019, respectively. Payables associated with these transactions were $— million and $1 million as of December 31, 2021 and 2020, respectively.
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Supplemental disclosure of cash flow information - | | | | | |
Interest paid, net of amounts capitalized | $ | 166 |
| | $ | 167 |
| | $ | 173 |
|
Income taxes paid | $ | 117 |
| | $ | 89 |
| | $ | — |
|
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 34 |
| | $ | 18 |
| | $ | 19 |
|
Capital and financial lease obligations incurred | $ | 1 |
| | $ | — |
| | $ | (1 | ) |
Nevada Power incurs intercompany administrative and shared facility costs with NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. Nevada Power provided services to NV Energy of $1 million, $— million and $— million for each of the years ending December 31, 2021, 2020 and 2019, respectively. NV Energy provided services to Nevada Power of $9 million for the years ending December 31, 2021, 2020 and 2019. Nevada Power provided services to Sierra Pacific of $25 million, $26 million and $26 million for the years ended December 31, 2021, 2020 and 2019, respectively. Sierra Pacific provided services to Nevada Power of $15 million, $15 million and $14 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included amounts due to NV Energy of $33 million and $28 million, respectively. There were no receivables due from NV Energy as of December 31, 2021 and 2020. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included receivables due from Sierra Pacific of $2 million. There were no payables due to Sierra Pacific as of December 31, 2021 and 2020.
(16) Unaudited Quarterly Operating Results (in millions)Nevada Power is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. As of December 31, 2021 and 2020 federal income taxes receivable from NV Energy were $27 million and $— million, respectively. Nevada Power made cash payments of $63 million, $50 million and $113 million for federal income taxes for the years ended December 31, 2021, 2020 and 2019, respectively.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Nevada Power and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
|
| | | | | | | | | | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2018 | | 2018 | | 2018 | | 2018 |
| | | | | | | |
Operating revenues | $ | 395 |
| | $ | 562 |
| | $ | 820 |
| | $ | 407 |
|
Operating income | 40 |
| | 122 |
| | 247 |
| | 37 |
|
Net income | — |
| | 64 |
| | 164 |
| | (2 | ) |
| | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2017 | | 2017 | | 2017 | | 2017 |
| | | | | | | |
Operating revenues | $ | 392 |
| | $ | 574 |
| | $ | 819 |
| | $ | 421 |
|
Operating income | 52 |
| | 157 |
| | 317 |
| | 37 |
|
Net income | 10 |
| | 77 |
| | 176 |
| | (8 | ) |
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
Item 6. Selected Financial Data
Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Sierra Pacific's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy, natural gas and resources. Sierra Pacific's electric segment is summer peaking experiencing its highest retail energy sales in response to the demand for air conditioning and its natural gas segment is winter peaking due to sales in response to the demand for heating. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Sierra Pacific. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Sierra Pacific.
The following is management's discussion and analysis of certain significant factors that have affected the financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 20182021 was $92$124 million, a decreasean increase of $17$13 million, or 16%12%, compared to 2017,2020, primarily due to $23$5 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, $4 million of higher electric utility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from the residential customer class, partially offset by lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, $4 million of higher other, net, mainly due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies, $3 million of higher allowance for equity funds, mainly due to higher construction work-in-progress, $2 million of higher natural gas utility margin, mainly due to higher commercial usage, and $2 million of lower interest expense, mainly due to lower carrying charges on regulatory balances, partially offset by $3 million of higher income tax expense primarily due to higher pretax income, $2 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant in-service, and $1 million of higher operations and maintenance expense, primarilyexpenses, mainly due to increased political activityhigher plant operations and maintenance expenses and $15 million of lower electric utility margin, primarily due to lower average retail rates including rate impacts related to the tax rate reduction rider as a result of the Tax Cuts and Jobs Act (the "2017 Tax Reform"). These decreases were partiallyhigher legal expenses, offset by lower income tax expense of $25 million, primarily from a lower federal tax rate due to the impact of the 2017 Tax Reform.earnings sharing.
Net income for the year ended December 31, 20172020 was $109$111 million, an increase of $25$8 million, or 30%8%, compared to 2016, which includes $12019, primarily due to $13 million of lower income tax benefit from 2017 Tax Reform. Excluding the impact of 2017 Tax Reform, adjusted net income was $108 million, an increase of $24 million compared to 2016,expense due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 1, 2020, $10 million of lower interest on deferred chargesoperations and long-term debtmaintenance expenses, primarily due to higher regulatory-directed credits, and $4 million of $11 million, higher electric utility marginsmargin, partially offset by $16 million of $8 million, lowerhigher depreciation and amortization, primarilymainly due to regulatory amortizationshigher plant in-service, and $3 million of $4 million and lower operating costs of $4 million. The increase in electricnatural gas utility margin was due to the impacts of weather, higher transmission revenue and customer usage patterns, partially offset by lower wholesale revenue due to lower volumes.margin.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Sierra Pacific's expenses included in regulatory recovery mechanisms result in comparable to changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 848 | | | $ | 738 | | | $ | 110 | | 15 | % | | $ | 738 | | | $ | 770 | | | $ | (32) | | (4) | % |
Cost of fuel and energy | | 407 | | | 301 | | | 106 | | 35 | | | 301 | | | 337 | | | (36) | | (11) | |
Electric utility margin | | 441 | | | 437 | | | 4 | | 1 | % | | 437 | | | 433 | | | 4 | | 1 | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 117 | | | 116 | | | 1 | | 1 | % | | 116 | | | 119 | | | (3) | | (3) | % |
Natural gas purchased for resale | | 61 | | | 62 | | | (1) | | (2) | | | 62 | | | 62 | | | — | | — | |
Natural gas utility margin | | 56 | | | 54 | | | 2 | | 4 | % | | 54 | | | 57 | | | (3) | | (5) | % |
| | | | | | | | | | | | | | |
Utility margin | | 497 | | | 491 | | | 6 | | 1 | % | | 491 | | | 490 | | | 1 | | — | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | 163 | | | 162 | | | 1 | | 1 | % | | 162 | | | 172 | | | (10) | | (6) | % |
Depreciation and amortization | | 143 | | | 141 | | | 2 | | 1 | | | 141 | | | 125 | | | 16 | | 13 | |
Property and other taxes | | 24 | | | 23 | | | 1 | | 4 | | | 23 | | | 22 | | | 1 | | 5 | |
Operating income | | $ | 167 | | | $ | 165 | | | $ | 2 | | 1 | % | | $ | 165 | | | $ | 171 | | | $ | (6) | | (4) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Electric operating revenue | | $ | 752 |
| | $ | 713 |
| | $ | 39 |
| 5 | % | | $ | 713 |
| | $ | 702 |
| | $ | 11 |
| 2 | % |
Cost of fuel and energy | | 322 |
| | 268 |
| | 54 |
| 20 |
| | 268 |
| | 265 |
| | 3 |
| 1 |
|
Electric utility margin | | 430 |
| | 445 |
| | (15 | ) | (3 | ) | | 445 |
| | 437 |
| | 8 |
| 2 |
|
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Natural gas operating revenue | | 103 |
| | 99 |
| | 4 |
| 4 | % | | 99 |
| | 110 |
| | (11 | ) | (10 | )% |
Cost of natural gas purchased for resale | | 49 |
| | 42 |
| | 7 |
| 17 |
| | 42 |
| | 55 |
| | (13 | ) | (24 | ) |
Natural gas utility margin | | 54 |
| | 57 |
| | (3 | ) | (5 | ) | | 57 |
| | 55 |
| | 2 |
| 4 |
|
| | | | | | | | | | | | | | |
Utility margin | | 484 |
| | 502 |
| | (18 | ) | (4 | )% | | 502 |
| | 492 |
| | 10 |
| 2 | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | 190 |
| | 167 |
| | 23 |
| 14 | % | | 167 |
| | 169 |
| | (2 | ) | (1 | )% |
Depreciation and amortization | | 119 |
| | 114 |
| | 5 |
| 4 |
| | 114 |
| | 118 |
| | (4 | ) | (3 | ) |
Property and other taxes | | 23 |
| | 24 |
| | (1 | ) | (4 | ) | | 24 |
| | 24 |
| | — |
| — |
|
Operating income | | $ | 152 |
| | $ | 197 |
| | $ | (45 | ) | (23 | ) | | $ | 197 |
| | $ | 181 |
| | $ | 16 |
| 9 |
|
A comparison of Sierra Pacific's key operating results is as follows:
Electric Utility Margin
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Electric utility margin (in millions): | | | | | | | | | | | | | | |
Electric operating revenue | | $ | 752 |
| | $ | 713 |
| | $ | 39 |
| 5 | % | | $ | 713 |
| | $ | 702 |
| | $ | 11 |
| 2 | % |
Cost of fuel and energy | | 322 |
| | 268 |
| | 54 |
| 20 |
| | 268 |
| | 265 |
| | 3 |
| 1 |
|
Electric utility margin | | $ | 430 |
| | $ | 445 |
| | $ | (15 | ) | (3 | ) | | $ | 445 |
| | $ | 437 |
| | $ | 8 |
| 2 |
|
| | | | | | | | | | | | | | |
GWhs sold: | | | | | | | | | | | | | | |
Residential | | 2,483 |
| | 2,492 |
| | (9 | ) | — | % | | 2,492 |
| | 2,375 |
| | 117 |
| 5 | % |
Commercial | | 2,998 |
| | 2,954 |
| | 44 |
| 1 |
| | 2,954 |
| | 2,933 |
| | 21 |
| 1 |
|
Industrial | | 3,387 |
| | 3,176 |
| | 211 |
| 7 |
| | 3,176 |
| | 3,014 |
| | 162 |
| 5 |
|
Other | | 16 |
| | 16 |
| | — |
| — |
| | 16 |
| | 16 |
| | — |
| — |
|
Total fully bundled(1) | | 8,884 |
| | 8,638 |
| | 246 |
| 3 |
| | 8,638 |
| | 8,338 |
| | 300 |
| 4 |
|
Distribution only service | | 1,516 |
| | 1,394 |
| | 122 |
| 9 |
| | 1,394 |
| | 1,360 |
| | 34 |
| 3 |
|
Total retail | | 10,400 |
| | 10,032 |
| | 368 |
| 4 |
| | 10,032 |
| | 9,698 |
| | 334 |
| 3 |
|
Wholesale | | 558 |
| | 561 |
| | (3 | ) | (1 | ) | | 561 |
| | 662 |
| | (101 | ) | (15 | ) |
Total GWhs sold | | 10,958 |
| | 10,593 |
| | 365 |
| 3 |
| | 10,593 |
| | 10,360 |
| | 233 |
| 2 |
|
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands): | | | | | | | | | | | | | | |
Residential | | 300 |
| | 295 |
| | 5 |
| 2 | % | | 295 |
| | 291 |
| | 4 |
| 1 | % |
Commercial | | 47 |
| | 47 |
| | — |
| — |
| | 47 |
| | 47 |
| | — |
| — |
|
Total | | 347 |
| | 342 |
| | 5 |
| 1 |
| | 342 |
| | 338 |
| | 4 |
| 1 |
|
| | | | | | | | | | | | | | |
Average per MWh: | | | | | | | | | | | | | | |
Revenue - retail fully bundled(1) | | $ | 78.32 |
| | $ | 76.90 |
| | $ | 1.42 |
| 2 | % | | $ | 76.90 |
| | $ | 78.08 |
| | $ | (1.18 | ) | (2 | )% |
Revenue - wholesale | | $ | 50.11 |
| | $ | 50.29 |
| | $ | (0.18 | ) | — | % | | $ | 50.29 |
| | $ | 52.05 |
| | $ | (1.76 | ) | (3 | )% |
Total cost of energy(2)(3) | | $ | 32.96 |
| | $ | 27.35 |
| | $ | 5.61 |
| 21 | % | | $ | 27.35 |
| | $ | 28.16 |
| | $ | (0.81 | ) | (3 | )% |
| | | | | | | | | | | | | | |
Heating degree days | | 4,450 |
| | 4,523 |
| | (73 | ) | (2 | )% | | 4,523 |
| | 4,185 |
| | 338 |
| 8 | % |
Cooling degree days | | 1,290 |
| | 1,401 |
| | (111 | ) | (8 | )% | | 1,401 |
| | 1,088 |
| | 313 |
| 29 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(3)(4): | | | | | | | | | | | | | | |
Natural gas | | 4,681 |
| | 4,280 |
| | 401 |
| 9 | % | | 4,280 |
| | 4,290 |
| | (10 | ) | — | % |
Coal | | 834 |
| | 457 |
| | 377 |
| 82 |
| | 457 |
| | 751 |
| | (294 | ) | (39 | ) |
Renewables(5) | | 35 |
| | 36 |
| | (1 | ) | (3 | ) | | 36 |
| | — |
| | 36 |
| — |
|
Total energy generated | | 5,550 |
| | 4,773 |
| | 777 |
| 16 |
| | 4,773 |
| | 5,041 |
| | (268 | ) | (5 | ) |
Energy purchased | | 4,229 |
| | 5,017 |
| | (788 | ) | (16 | ) | | 5,017 |
| | 4,383 |
| | 634 |
| 14 |
|
Total | | 9,779 |
| | 9,790 |
| | (11 | ) | — |
| | 9,790 |
| | 9,424 |
| | 366 |
| 4 |
|
A comparison of key operating results related to electric utility margin is as follows for the years ended December 31: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 848 | | | $ | 738 | | | $ | 110 | | 15 | % | | $ | 738 | | | $ | 770 | | | $ | (32) | | (4) | % |
Cost of fuel and energy | | 407 | | | 301 | | | 106 | | 35 | | | 301 | | | 337 | | | (36) | | (11) | |
Utility margin | | $ | 441 | | | $ | 437 | | | $ | 4 | | 1 | % | | $ | 437 | | | $ | 433 | | | $ | 4 | | 1 | % |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 2,769 | | | 2,672 | | | 97 | | 4 | % | | 2,672 | | | 2,491 | | | 181 | | 7 | % |
Commercial | | 3,056 | | | 2,977 | | | 79 | | 3 | | | 2,977 | | | 2,973 | | | 4 | | — | |
Industrial | | 3,716 | | | 3,544 | | | 172 | | 5 | | | 3,544 | | | 3,716 | | | (172) | | (5) | |
Other | | 15 | | | 15 | | | — | | — | | | 15 | | | 16 | | | (1) | | (6) | |
Total fully bundled(1) | | 9,556 | | | 9,208 | | | 348 | | 4 | | | 9,208 | | | 9,196 | | | 12 | | — | |
Distribution only service | | 1,639 | | | 1,670 | | | (31) | | (2) | | | 1,670 | | | 1,629 | | | 41 | | 3 | |
Total retail | | 11,195 | | | 10,878 | | | 317 | | 3 | | | 10,878 | | | 10,825 | | | 53 | | — | |
Wholesale | | 656 | | | 548 | | | 108 | | 20 | | | 548 | | | 662 | | | (114) | | (17) | |
Total GWhs sold | | 11,851 | | | 11,426 | | | 425 | | 4 | % | | 11,426 | | | 11,487 | | | (61) | | (1) | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 365 | | | 359 | | | 6 | | 2 | % | | 359 | | | 352 | | | 7 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 81.77 | | | $ | 73.89 | | | $ | 7.88 | | 11 | % | | $ | 73.89 | | | $ | 76.72 | | | $ | (2.83) | | (4) | % |
Wholesale | | $ | 58.14 | | | $ | 52.52 | | | $ | 5.62 | | 11 | % | | $ | 52.52 | | | $ | 48.54 | | | $ | 3.98 | | 8 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 4,494 | | | 4,477 | | | 17 | | — | % | | 4,477 | | | 4,728 | | | (251) | | (5) | % |
Cooling degree days | | 1,366 | | | 1,176 | | | 190 | | 16 | % | | 1,176 | | | 1,107 | | | 69 | | 6 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 4,712 | | | 5,219 | | | (507) | | (10) | % | | 5,219 | | | 4,891 | | | 328 | | 7 | % |
Coal | | 1,220 | | | 855 | | | 365 | | 43 | | | 855 | | | 1,205 | | | (350) | | (29) | |
Renewables(4) | | 31 | | | 37 | | | (6) | | (16) | | | 37 | | | 37 | | | — | | — | |
Total energy generated | | 5,963 | | | 6,111 | | | (148) | | (2) | | | 6,111 | | | 6,133 | | | (22) | | — | |
Energy purchased | | 4,960 | | | 4,753 | | | 207 | | 4 | | | 4,753 | | | 4,466 | | | 287 | | 6 | |
Total | | 10,923 | | | 10,864 | | | 59 | | 1 | % | | 10,864 | | | 10,599 | | | 265 | | 3 | % |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(5): | | | | | | | | | | | | | | |
Energy generated | | $ | 28.84 | | | $ | 20.12 | | | $ | 8.72 | | 43 | % | | $ | 20.12 | | | $ | 26.29 | | | $ | (6.17) | | (23) | % |
Energy purchased | | $ | 47.39 | | | $ | 37.46 | | | $ | 9.93 | | 27 | % | | $ | 37.46 | | | $ | 39.39 | | | $ | (1.93) | | (5) | % |
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
| |
(2) | The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs. |
| |
(3) | The average total cost of energy per MWh and sources of energy excludes 54 GWhs of coal and 183 GWhs of gas generated energy that is purchased at cost by related parties for the year ended December 31, 2018. There were no GWhs of coal or gas excluded for the years ended December 31, 2017 and 2016. |
| |
(4) | GWh amounts are net of energy used by the related generating facilities. |
| |
(5) | Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific. |
(2) The average cost of energy per MWh and sources of energy excludes 2, 10 and - GWhs of coal and 6, 31 and - GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2021, 2020 and 2019, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) Includes the Fort Churchill Solar Array which was under lease by Sierra Pacific until it was acquired in December 2021.
(5) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Natural Gas Utility Margin
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Change | | 2017 | | 2016 | | Change |
Natural gas utility margin (in millions): | | | | | | | | | | | | | | |
Natural gas operating revenue | | $ | 103 |
| | $ | 99 |
| | $ | 4 |
| 4 | % | | $ | 99 |
| | $ | 110 |
| | $ | (11 | ) | (10 | )% |
Natural gas purchased for resale | | 49 |
| | 42 |
| | 7 |
| 17 |
| | 42 |
| | 55 |
| | (13 | ) | (24 | ) |
Natural gas utility margin | | $ | 54 |
| | $ | 57 |
| | $ | (3 | ) | (5 | ) | | $ | 57 |
| | $ | 55 |
| | $ | 2 |
| 4 |
|
| | | | | | | | | | | | | | |
Dth sold: | | | | | | | | | | | | | | |
Residential | | 10,102 |
| | 10,291 |
| | (189 | ) | (2 | )% | | 10,291 |
| | 9,207 |
| | 1,084 |
| 12 | % |
Commercial | | 5,128 |
| | 5,153 |
| | (25 | ) | — |
| | 5,153 |
| | 4,679 |
| | 474 |
| 10 |
|
Industrial | | 1,927 |
| | 1,822 |
| | 105 |
| 6 |
| | 1,822 |
| | 1,548 |
| | 274 |
| 18 |
|
Total retail | | 17,157 |
| | 17,266 |
| | (109 | ) | (1 | ) | | 17,266 |
| | 15,434 |
| | 1,832 |
| 12 |
|
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 167 |
| | 164 |
| | 3 |
| 2 | % | | 164 |
| | 162 |
| | 2 |
| 1 | % |
Average revenue per retail Dth sold: | | $ | 6.00 |
| | $ | 5.73 |
| | $ | 0.27 |
| 5 | % | | $ | 5.73 |
| | $ | 7.13 |
| | $ | (1.40 | ) | (20 | )% |
Average cost of natural gas per retail Dth sold | | $ | 2.86 |
| | $ | 2.43 |
| | $ | 0.43 |
| 18 | % | | $ | 2.43 |
| | $ | 3.56 |
| | $ | (1.13 | ) | (32 | )% |
Heating degree days | | 4,450 |
| | 4,523 |
| | (73 | ) | (2 | )% | | 4,523 |
| | 4,185 |
| | 338 |
| 8 | % |
A comparison of key operating results related to natural gas utility margin is as follows for the years ended December 31: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 117 | | | $ | 116 | | | $ | 1 | | 1 | % | | $ | 116 | | | $ | 119 | | | $ | (3) | | (3) | % |
Natural gas purchased for resale | | 61 | | | 62 | | | (1) | | (2) | | | 62 | | | 62 | | | — | | — | |
Utility margin | | $ | 56 | | | $ | 54 | | | $ | 2 | | 4 | % | | $ | 54 | | | $ | 57 | | | $ | (3) | | (5) | % |
| | | | | | | | | | | | | | |
Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 10,662 | | | 10,452 | | | 210 | | 2 | % | | 10,452 | | | 11,311 | | | (859) | | (8) | % |
Commercial | | 5,524 | | | 5,148 | | | 376 | | 7 | | | 5,148 | | | 5,783 | | | (635) | | (11) | |
Industrial | | 1,981 | | | 1,826 | | | 155 | | 8 | | | 1,826 | | | 1,971 | | | (145) | | (7) | |
Total retail | | 18,167 | | | 17,426 | | | 741 | | 4 | % | | 17,426 | | | 19,065 | | | (1,639) | | (9) | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 177 | | | 174 | | | 3 | | 2 | % | | 174 | | | 170 | | | 4 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | $ | 6.44 | | | $ | 6.66 | | | $ | (0.22) | | (3) | % | | $ | 6.66 | | | $ | 6.24 | | | $ | 0.42 | | 7 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 4,494 | | | 4,477 | | | 17 | | — | % | | 4,477 | | | 4,728 | | | (251) | | (5) | % |
| | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | $ | 3.36 | | | $ | 3.56 | | | $ | (0.20) | | (6) | % | | $ | 3.56 | | | $ | 3.25 | | | $ | 0.31 | | 9 | % |
Year Ended December 31, 20182021 Compared to Year Ended December 31, 20172020
Electric utility margin decreased $15 increased $4 million, or 3%1%, for 20182021 compared to 20172020 primarily due to:
•$10 million of higher electric retail utility margin primarily due to $18higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.9% primarily due to an increase in the average number of customers, favorable changes in customer usage patterns and the favorable impact of weather, and
•$3 million of higher transmission and wholesale revenue.
The increase in electric utility margin was offset by:
•$3 million in lower retail rates from the tax rate reduction rider asrevenue recognized due to a result of 2017 Tax Reform offset by $2favorable regulatory decision in 2020;
•$3 million of customer growth.due to an adjustment to regulatory-related revenue deferrals; and
•$2 million due to lower energy efficiency program costs (offset in operations and maintenance expense).
Natural gas utility margin increased $2 million, or 4%, for 2021 compared to 2020 primarily due to favorable changes in customer usage patterns.
Operations and maintenance increased $1 million, or 1%, for 2021 compared to 2020 primarily due to higher plant operations and maintenance expenses and higher legal expenses, offset by lower earnings sharing and lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $2 million, or 1%, for 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in-service.
Interest expense decreased $2 million, or 4%, for 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances.
Allowance for equity funds increased$3 million, or 75%, for 2021 compared to 2020 primarily due to higher construction work-in-progress.
Interest and dividend income increased $5 million for 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $4 million, or 57%, for 2021 compared to 2020 primarily due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies.
Income tax expense increased $3 million, or 20%, for 2021 compared to 2020 primarily due to higher pretax income. The effective tax rate was 13% in 2021 and 12% in 2020.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Electric utility margin increased $4 million, or 1%, for 2020 compared to 2019 primarily due to:
•$4 million in higher residential customer volumes from the favorable impact of weather;
•$3 million due to higher energy efficiency program costs (offset in operations and maintenance expense); and
•$2 million of residential customer growth.
The increase in electric utility margin was offset by:
•$4 million of lower transmission and wholesale revenue; and
•$1 million of higher revenue reductions related to customer service agreements.
Natural gas utility margin decreased $3 million, or 5%, for 20182020 compared to 20172019 primarily due to lower retail ratescustomer volumes mainly from the tax rate reduction rider as a resultunfavorable impacts of 2017 Tax Reform.weather.
Operations and maintenance increased $23 decreased $10 million, or 14%6%, for 20182020 compared to 20172019 primarily due to increased political activity expenses.higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) of $9 million and lower plant operations and maintenance expenses, offset by lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019 and higher energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $5$16 million, or 4%13%, for 20182020 compared to 20172019 primarily due to higher plant placed in-service and higher depreciation expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in service.operations and maintenance expense).
Other income (expense) is favorable $3$1 million, or 9%3%, for 20182020 compared to 20172019 primarily due to lower pension expense.costs, partially offset by higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Income tax expense decreased $25$13 million, or 45%46%, for 20182020 compared to 2017.2019. The effective tax rate was 25%12% in 20182020 and 34%21% in 2017. The decrease in the effective tax rate is primarily2019 and decreased due to 2017 Tax Reform, which reduced the United States federal corporaterecognition of amortization of excess deferred income tax rate from 35% to 21%,taxes following regulatory approval effective January 1, 2018, offset by an increase in nondeductible expenses.2020.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Electric utility margin increased $8 million or 2% for 2017 compared to 2016 due to:
$8 million higher customer usage primarily from the impacts of weather;
$3 million in higher transmission revenue; and
$2 million from customer usage patterns.
The increase in gross margin was offset by:
$6 million in decreased wholesale revenue due to lower volumes.
Natural gas utility margin increased $2 million, or 4%, for 2017 compared to 2016 primarily due to higher customer usage from the impacts of weather.
Operations and maintenance decreased $2 million, or 1%, for 2017 compared to 2016 primarily due to disallowances resulting from the settlement of the regulatory rate review in 2016 of $5 million.
Depreciation and amortization decreased $4 million, or 3%, for 2017 compared to 2016 primarily due to the expiration of various regulatory amortizations.
Other income (expense) is favorable $15 million, or 31%, for 2017 compared to 2016 primarily due to a decrease in interest expense from lower rates on outstanding debt balances, lower interest expense on deferred charges and an increase in allowance for funds used during construction.
Income tax expense increased $6 million, or 12%, for 2017 compared to 2016. The effective tax rate was 34% for 2017 and 37% for 2016. The decrease in the effective tax rate is primarily due to the effects of 2017 Tax Reform.
Liquidity and Capital Resources
As of December 31, 2018,2021, Sierra Pacific's total net liquidity was $241$101 million as follows (in millions):
|
| | | | |
Cash and cash equivalents | | $ | 71 |
|
| | |
Credit facilities(1) | | 250 |
|
Less - | | |
Letters of credit and tax-exempt bond support | | (80 | ) |
Net credit facilities | | 170 |
|
| | |
Total net liquidity | | $ | 241 |
|
Credit facilities: | | |
Maturity dates | | 2021 |
|
| | | | | | | | |
(1)Cash and cash equivalents | | $ | 10 | |
| | |
Refer to Note 6 of Notes to Financial Statements in Item 8 of this Form 10Credit facilities(1)
| | 250 | |
Less -K for further discussion regarding Sierra Pacific's | | |
Short-term debt | | (159) | |
| | |
Net credit facility.facilities | | 91 | |
| | |
Total net liquidity | | $ | 101 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Sierra Pacific's credit facility.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 20182021 and 20172020 were $275$183 million and $181$190 million, respectively. The change was primarily due to a decrease inthe timing of payments for fuel costs and an increase in collections from customers from higher deferred energy rates,costs, partially offset by higher collections from customers, the timing of payments for operating costs, higher federal tax paymentslower inventory purchases and higher contributions to the pension plan.increased collections of customer advances.
Net cash flows from operating activities for the years ended December 31, 20172020 and 20162019 were $181$190 million and $243$237 million, respectively. The change was primarily due to lower collections from customers, higher inventory purchases, the timing of payments for operating costs and higher payments for fuel and energy costs, partially offset by lower contributions to the pension plan.payments for income taxes.
The timing of Sierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 20182021 and 20172020 were $(205)$(300) million and $(186)$(246) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 20172020 and 20162019 were $(186)$(246) million and $(194)$(247) million, respectively. The change was primarily due to decreased capital expenditures, partially offset by expenditures related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the years ended December 31, 20182021 and 20172020 were $(2)$107 million and $(47)$50 million, respectively. The change was primarily due to higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the issuance of $45 million in 2017.long-term debt.
Net cash flows from financing activities for the years ended December 31, 20172020 and 20162019 were $(47)$50 million and $(100)$(34) million, respectively. The change was primarily due to lower repayments ofpayments to repurchase long-term debt, higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc. in 2017,, partially offset by lower proceeds from issuancethe re-offering of previously repurchased long-term debt.
Ability to Issue Debt
Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2018,2021, Sierra Pacific has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Sierra Pacific's $250 million secured credit facility) does not exceed $1.6 billion as measured at the end of each calendar quarter. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of December 31, 2018.2021. In addition, certain financing agreements contain covenants which are currently suspended as Sierra Pacific's senior secured debt is rated investment grade. However, if Sierra Pacific's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Sierra Pacific would be subject to limitations under these covenants.
In January 2022, the PUCN approved Sierra Pacific's request to increase its financing authority for debt securities to not exceed $1.9 billion as measured at the end of each calendar quarter. Additionally, the PUCN authorized Sierra Pacific to issue common and preferred stock so long as the total amounts outstanding do not exceed $2.2 billion and $500 million, respectively, at the end of each calendar quarter.
Ability to Issue General and Refunding Mortgage Securities
To the extent Sierra Pacific has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Sierra Pacific's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Sierra Pacific's indenture.
Sierra Pacific's indenture creates a lien on substantially all of Sierra Pacific's properties in Nevada. As of December 31, 2021, $4.5 billion of Sierra Pacific's assets were pledged. Sierra Pacific had the capacity to issue $1.7 billion of additional general and refunding mortgage securities as of December 31, 2021 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Sierra Pacific also has the ability to release property from the lien of Sierra Pacific's indenture on the basis of net property additions, cash or retired bonds. To the extent Sierra Pacific releases property from the lien of Sierra Pacific's indenture, it will reduce the amount of securities issuable under the indenture.
Common Shareholder's Equity
In January 2022, Sierra Pacific received a capital contribution of $130 million from NV Energy, Inc.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including Sierra Pacific's credit ratings, investors' judgment of risk associated with Sierra Pacific and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Electric distribution | $ | 156 | | | $ | 128 | | | $ | 96 | | | $ | 122 | | | $ | 129 | | | $ | 112 | |
Electric transmission | 17 | | | 60 | | | 77 | | | 164 | | | 242 | | | 326 | |
Solar generation | — | | | — | | | 17 | | | 1 | | | 134 | | | 197 | |
Other | 72 | | | 58 | | | 110 | | | 160 | | | 100 | | | 74 | |
Total | $ | 245 | | | $ | 246 | | | $ | 300 | | | $ | 447 | | | $ | 605 | | | $ | 709 | |
Sierra Pacific received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its latest IRP filing in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar generation includes growth projects consisting of two solar photovoltaic facilities. The first project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. Both facilities will be jointly owned and operated by Nevada Power and Sierra Pacific.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
Sierra Pacific has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7) and AROs (refer to Note 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Sierra Pacific has cash requirements relating to interest payments of $411 million on long-term debt, including $41 million due in 2022.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Sierra Pacific's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Sierra Pacific is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Sierra Pacific's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Sierra Pacific has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Sierra Pacific's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, Sierra Pacific would have been required to post $18 million of additional collateral. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where Sierra Pacific operates has not had a significant impact on Sierra Pacific's financial results. Sierra Pacific operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Sierra Pacific is allowed to include prudent costs in its rates, including the impact of inflation after Sierra Pacific experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Sierra Pacific attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Sierra Pacific's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Sierra Pacific's Summary of Significant Accounting Policies included in Sierra Pacific's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Sierra Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $440 million and total regulatory liabilities were $463 million as of December 31, 2021. Refer to Sierra Pacific's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Sierra Pacific would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Sierra Pacific's results of operations.
Income Taxes
In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local income tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Sierra Pacific's financial results. Refer to Sierra Pacific's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's income taxes.
It is probable that Sierra Pacific will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to its customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $234 million and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $78 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Sierra Pacific's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Sierra Pacific's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Sierra Pacific transacts. The following discussion addresses the significant market risks associated with Sierra Pacific's business activities. Sierra Pacific has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's contracts accounted for as derivatives.
Commodity Price Risk
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Sierra Pacific's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Sierra Pacific's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | (33) | | | $ | (26) | | | $ | (40) | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | 7 | | | $ | 8 | | | $ | 6 | |
Sierra Pacific's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose Sierra Pacific to earnings volatility. As of December 31, 2021 and 2020, a net regulatory asset of $33 million and net regulatory liability of $7 million, respectively, was recorded related to the net derivative liability of $33 million and net derivative asset of $7 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Sierra Pacific is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Sierra Pacific's fixed-rate long-term debt does not expose Sierra Pacific to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Sierra Pacific were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Sierra Pacific's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Sierra Pacific's short- and long-term debt.
As of December 31, 2021 and 2020, Sierra Pacific had short-term variable-rate obligations totaling $159 million and $45 million, respectively, that expose Sierra Pacific to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Sierra Pacific's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, Sierra Pacific's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sierra Pacific as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Sierra Pacific's management. Our responsibility is to express an opinion on Sierra Pacific's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Sierra Pacific is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Sierra Pacific's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Sierra Pacific is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Sierra Pacific operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense, and income tax expense.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Sierra Pacific an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Sierra Pacific Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Sierra Pacific's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Sierra Pacific's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected Sierra Pacific's filings with the Commissions and the filings with the Commissions by intervenors that may impact Sierra Pacific's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 25, 2022
We have served as Sierra Pacific's auditor since 1996.
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 10 | | | $ | 19 | |
Trade receivables, net | 128 | | | 97 | |
| | | |
Inventories | 65 | | | 77 | |
Regulatory assets | 177 | | | 67 | |
| | | |
Other current assets | 35 | | | 45 | |
Total current assets | 415 | | | 305 | |
| | | |
Property, plant and equipment, net | 3,340 | | | 3,164 | |
Regulatory assets | 263 | | | 267 | |
Other assets | 205 | | | 183 | |
| | | |
Total assets | $ | 4,223 | | | $ | 3,919 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 147 | | | $ | 108 | |
Accrued interest | 14 | | | 14 | |
Accrued property, income and other taxes | 16 | | | 14 | |
Short-term debt | 159 | | | 45 | |
| | | |
Regulatory liabilities | 19 | | | 34 | |
Customer deposits | 15 | | | 15 | |
Other current liabilities | 44 | | | 25 | |
Total current liabilities | 414 | | | 255 | |
| | | |
Long-term debt | 1,164 | | | 1,164 | |
Finance lease obligations | 106 | | | 121 | |
Regulatory liabilities | 444 | | | 463 | |
Deferred income taxes | 402 | | | 374 | |
Other long-term liabilities | 158 | | | 131 | |
Total liabilities | 2,688 | | | 2,508 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | |
Additional paid-in capital | 1,111 | | | 1,111 | |
Retained earnings | 425 | | | 301 | |
Accumulated other comprehensive loss, net | (1) | | | (1) | |
Total shareholder's equity | 1,535 | | | 1,411 | |
| | | |
Total liabilities and shareholder's equity | $ | 4,223 | | | $ | 3,919 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue: | | | | | |
Regulated electric | $ | 848 | | | $ | 738 | | | $ | 770 | |
Regulated natural gas | 117 | | | 116 | | | 119 | |
Total operating revenue | 965 | | | 854 | | | 889 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 407 | | | 301 | | | 337 | |
Cost of natural gas purchased for resale | 61 | | | 62 | | | 62 | |
Operations and maintenance | 163 | | | 162 | | | 172 | |
Depreciation and amortization | 143 | | | 141 | | | 125 | |
Property and other taxes | 24 | | | 23 | | | 22 | |
| | | | | |
Total operating expenses | 798 | | | 689 | | | 718 | |
| | | | | |
Operating income | 167 | | | 165 | | | 171 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (54) | | | (56) | | | (48) | |
Allowance for borrowed funds | 2 | | | 2 | | | 1 | |
Allowance for equity funds | 7 | | | 4 | | | 3 | |
Interest and dividend income | 9 | | | 4 | | | 3 | |
Other, net | 11 | | | 7 | | | 1 | |
Total other income (expense) | (25) | | | (39) | | | (40) | |
| | | | | |
Income before income tax expense | 142 | | | 126 | | | 131 | |
Income tax expense | 18 | | | 15 | | | 28 | |
Net income | $ | 124 | | | $ | 111 | | | $ | 103 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Retained | | Accumulated | | |
| | | | | | Other | | Earnings | | Other | | Total |
| | Common Stock | | Paid-in | | (Accumulated | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Deficit) | | Loss, Net | | Equity |
Balance, December 31, 2018 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 153 | | | $ | — | | | $ | 1,264 | |
Net income | | — | | | — | | | — | | | 103 | | | — | | | 103 | |
Dividends declared | | — | | | — | | | — | | | (46) | | | — | | | (46) | |
Other equity transactions | | — | | | — | | | — | | | — | | | (1) | | | (1) | |
Balance, December 31, 2019 | | 1,000 | | | — | | | 1,111 | | | 210 | | | (1) | | | 1,320 | |
Net income | | — | | | — | | | — | | | 111 | | | — | | | 111 | |
Dividends declared | | — | | | — | | | — | | | (20) | | | — | | | (20) | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | — | | | 1,111 | | | 301 | | | (1) | | | 1,411 | |
Net income | | — | | | — | | | — | | | 124 | | | — | | | 124 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 124 | | | $ | 111 | | | $ | 103 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 143 | | | 141 | | | 125 | |
Allowance for equity funds | (7) | | | (4) | | | (3) | |
Changes in regulatory assets and liabilities | (39) | | | (33) | | | 25 | |
Deferred income taxes and amortization of investment tax credits | 13 | | | 12 | | | 9 | |
Deferred energy | (116) | | | (17) | | | 15 | |
Amortization of deferred energy | 29 | | | (14) | | | (2) | |
Other, net | (1) | | | (2) | | | — | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | (27) | | | (81) | | | (6) | |
Inventories | 12 | | | (19) | | | (5) | |
Accrued property, income and other taxes | 9 | | | 9 | | | (16) | |
Accounts payable and other liabilities | 43 | | | 87 | | | (8) | |
Net cash flows from operating activities | 183 | | | 190 | | | 237 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (300) | | | (246) | | | (248) | |
| | | | | |
Other, net | — | | | — | | | 1 | |
Net cash flows from investing activities | (300) | | | (246) | | | (247) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | 30 | | | 125 | |
Repayments of long-term debt | — | | | — | | | (109) | |
Net proceeds from short-term debt | 114 | | | 45 | | | — | |
Dividends paid | — | | | (20) | | | (46) | |
Other, net | (7) | | | (5) | | | (4) | |
Net cash flows from financing activities | 107 | | | 50 | | | (34) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (10) | | | (6) | | | (44) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 26 | | | 32 | | | 76 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 16 | | | $ | 26 | | | $ | 32 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Presentation
The Consolidated Financial Statements include the accounts of Sierra Pacific and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Sierra Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Sierra Pacific's assessment of the collectability of amounts owed to Sierra Pacific by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Sierra Pacific primarily utilizes credit loss history. However, Sierra Pacific may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Sierra Pacific also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The changes in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 2 | | | $ | 2 | | | $ | 2 | |
Charged to operating costs and expenses, net | 2 | | | 2 | | | 1 | |
Write-offs, net | (3) | | | (2) | | | (1) | |
Ending balance | $ | 1 | | | $ | 2 | | | $ | 2 | |
Derivatives
Sierra Pacific employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Consolidated Statements of Operations.
For Sierra Pacific's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies totaling $62 million and $67 million as of December 31, 2021 and 2020, respectively, and fuel, which includes coal stock, stored natural gas and fuel oil, totaling $3 million and $10 million as of December 31, 2021 and 2020, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Sierra Pacific capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Sierra Pacific's various regulatory authorities. Depreciation studies are completed by Sierra Pacific to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Sierra Pacific retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Sierra Pacific is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Sierra Pacific's AFUDC rate used during 2021 and 2020 was 6.75% for electric, 5.75% for natural gas and 6.65% for common facilities.
Asset Retirement Obligations
Sierra Pacific recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Sierra Pacific's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
Sierra Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the option. Sierra Pacific's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Sierra Pacific's operating and finance right-of-use assets are recorded in other assets and the operating and current finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Income Taxes
Berkshire Hathaway includes Sierra Pacific in its consolidated United States federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that Sierra Pacific deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Sierra Pacific's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Sierra Pacific uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Sierra Pacific expects to be entitled in exchange for those goods or services. Sierra Pacific records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Sierra Pacific's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 842, "Leases" and amounts not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."
Revenue recognized is equal to what Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $78 million and $59 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,163 | | | $ | 1,130 | |
Electric transmission | 50 - 100 years | | 940 | | | 908 | |
Electric distribution | 20 - 100 years | | 1,846 | | | 1,754 | |
Electric general and intangible plant | 5 - 70 years | | 204 | | | 189 | |
Natural gas distribution | 35 - 70 years | | 438 | | | 429 | |
Natural gas general and intangible plant | 5 - 70 years | | 14 | | | 15 | |
Common general | 5 - 70 years | | 370 | | | 355 | |
Utility plant | | | 4,975 | | | 4,780 | |
Accumulated depreciation and amortization | | | (1,854) | | | (1,755) | |
Utility plant, net | | | 3,121 | | | 3,025 | |
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | — | | | 2 | |
Plant, net | | | 3,121 | | | 3,027 | |
Construction work-in-progress | | | 219 | | | 137 | |
Property, plant and equipment, net | | | $ | 3,340 | | | $ | 3,164 | |
All of Sierra Pacific's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Sierra Pacific's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2021, 2020 and 2019 was 3.1%, 3.2% and 3.1%, respectively. Sierra Pacific is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2016.
Construction work-in-progress is primarily related to the construction of regulated assets.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements, Sierra Pacific, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Sierra Pacific accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Sierra Pacific's share of the expenses of these facilities.
The amounts shown in the table below represent Sierra Pacific's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Sierra | | | | | | Construction |
| Pacific's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Valmy Generating Station | 50 | % | | $ | 394 | | | $ | 309 | | | $ | 1 | |
ON Line Transmission Line | 6 | | | 40 | | | 8 | | | — | |
Valmy Transmission | 50 | | | 4 | | | 2 | | | — | |
Total | | | $ | 438 | | | $ | 319 | | | $ | 1 | |
(5) Leases
The following table summarizes Sierra Pacific's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 15 | | | $ | 16 | |
Finance leases | 111 | | | 126 | |
Total right-of-use assets | $ | 126 | | | $ | 142 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 15 | | | $ | 16 | |
Finance leases | 115 | | | 130 | |
Total lease liabilities | $ | 130 | | | $ | 146 | |
The following table summarizes Sierra Pacific's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 86 | | | $ | 78 | | | $ | 69 | |
Operating | 1 | | | 2 | | | 1 | |
Finance: | | | | | |
Amortization | 5 | | | 4 | | | 2 | |
Interest | 9 | | | 9 | | | 2 | |
| | | | | |
Total lease costs | $ | 101 | | | $ | 93 | | | $ | 74 | |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 27.4 | | 27.2 | | 26.3 |
Finance leases | 28.4 | | 27.8 | | 20.9 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 5.0 | % | | 5.0 | % | | 5.0 | % |
Finance leases | 8.2 | % | | 8.1 | % | | 7.1 | % |
The following table summarizes Sierra Pacific's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
Operating cash flows from operating leases | $ | (1) | | | $ | (2) | | | $ | (3) | |
Operating cash flows from finance leases | (9) | | | (6) | | | (3) | |
Financing cash flows from finance leases | (7) | | | (5) | | | (3) | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | |
| | | | | |
Finance leases | $ | 1 | | | $ | 89 | | | $ | 5 | |
Sierra Pacific has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 1 | | | $ | 16 | | | $ | 17 | |
2023 | 1 | | | 16 | | | 17 | |
2024 | 1 | | | 15 | | | 16 | |
2025 | 1 | | | 15 | | | 16 | |
2026 | 1 | | | 15 | | | 16 | |
Thereafter | 24 | | | 149 | | | 173 | |
Total undiscounted lease payments | 29 | | | 226 | | | 255 | |
Less - amounts representing interest | (14) | | | (111) | | | (125) | |
Lease liabilities | $ | 15 | | | $ | 115 | | | $ | 130 | |
Operating and Finance Lease Obligations
Sierra Pacific's operating and finance lease obligations consist mainly of ON Line and Truckee-Carson Irrigation District ("TCID"). ON Line was placed in-service on December 31, 2013. Sierra Pacific and Nevada Power, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the necessary procedures to change the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved ownership percentage change from Nevada Power to Sierra Pacific. The term of the lease is 41 years with the agreement ending December 31, 2054. In 1999, Sierra Pacific entered into a 50-year agreement with TCID to lease electric distribution facilities. Total finance lease obligations of $110 million and $122 million were included on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively, for these leases. See Note 2 for further discussion of Sierra Pacific's remaining lease obligations.
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. Sierra Pacific's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred energy costs | 1 year | | $ | 107 | | | $ | 22 | |
Merger costs from 1999 merger | 25 years | | 66 | | | 68 | |
Natural disaster protection plan | 1 year | | 62 | | | 45 | |
Employee benefit plans(1) | 8 years | | 46 | | | 81 | |
Unrealized loss on regulated derivative contracts | 1 year | | 35 | | | 2 | |
Deferred operating costs | 8 years | | 31 | | | 27 | |
Abandoned projects | 5 years | | 19 | | | 22 | |
| | | | | |
| | | | | |
Other | Various | | 74 | | | 67 | |
Total regulatory assets | | | $ | 440 | | | $ | 334 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 177 | | | $ | 67 | |
Noncurrent assets | | | 263 | | | 267 | |
Total regulatory assets | | | $ | 440 | | | $ | 334 | |
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
Sierra Pacific had regulatory assets not earning a return on investment of $158 million and $149 million as of December 31, 2021 and 2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, a portion of the employee benefit plans, losses on reacquired debt, AROs and legacy meters.
Regulatory Liabilities
Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Sierra Pacific's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 234 | | | $ | 249 | |
Cost of removal(2) | 36 years | | 201 | | | 197 | |
| | | | | |
| | | | | |
Other | Various | | 28 | | | 51 | |
Total regulatory liabilities | | | $ | 463 | | | $ | 497 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 19 | | | $ | 34 | |
Noncurrent liabilities | | | 444 | | | 463 | |
Total regulatory liabilities | | | $ | 463 | | | $ | 497 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Natural Disaster Protection Plan ("NDPP")
In March 2021, Sierra Pacific filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Sierra Pacific filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Sierra Pacific and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")
EEPR was established to allow Sierra Pacific to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Sierra Pacific. When Sierra Pacific's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2021, Sierra Pacific filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2020, including carrying charges. In August 2021, the PUCN issued an order accepting a stipulation requiring Sierra Pacific to refund the 2020 revenue and reset the rates as filed effective October 1, 2021.The EEIR liability for Sierra Pacific is $1 million and $2 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively.
(7)Short-term Debt and Credit Facilities
The following table summarizes Sierra Pacific's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | | | | | | | |
| | 2021 | | 2020 |
Credit facilities | | $ | 250 | | | $ | 250 | |
Short-term debt | | (159) | | | (45) | |
| | | | |
Net credit facilities | | $ | 91 | | | $ | 205 | |
Sierra Pacific has a $250 million secured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long‑term debt securities. As of December 31, 2021 and 2020, Sierra Pacific had borrowings of $159 million and $45 million, respectively, outstanding under the credit facility. As of December 31, 2021 and 2020, the weighted average interest rate on borrowings outstanding was 0.86% and 0.90%, respectively. Amounts due under Sierra Pacific's credit facility are collateralized by Sierra Pacific's general and refunding mortgage bonds. The credit facility requires Sierra Pacific's ratio of debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
(8) Long-term Debt
Sierra Pacific's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
General and refunding mortgage securities: | | | | | |
3.375% Series T, due 2023 | $ | 250 | | | $ | 249 | | | $ | 249 | |
2.600% Series U, due 2026 | 400 | | | 397 | | | 396 | |
6.750% Series P, due 2037 | 252 | | | 253 | | | 255 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
| | | | | |
1.850% Pollution Control Series 2016B, due 2029 (1) | 30 | | | 30 | | | 29 | |
| | | | | |
3.000% Gas and Water Series 2016B, due 2036 (2) | 60 | | | 60 | | | 61 | |
0.625% Water Facilities Series 2016C, due 2036 (1) | 30 | | | 30 | | | 30 | |
2.050% Water Facilities Series 2016D, due 2036 (1) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016E, due 2036 (1) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016F, due 2036 (1) | 75 | | | 75 | | | 74 | |
1.850% Water Facilities Series 2016G, due 2036 (1) | 20 | | | 20 | | | 20 | |
Total long-term debt | $ | 1,167 | | | $ | 1,164 | | | $ | 1,164 | |
| | | | | |
Reflected as - | | | | | |
| | | | | |
Long-term debt | | | $ | 1,164 | | | $ | 1,164 | |
| | | | | |
(1)Subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.
(2)Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt for the years beginning January 1, 2022 and thereafter, are as follows (in millions):
| | | | | |
| |
| |
| |
| |
2023 | $ | 250 | |
| |
| |
2026 | 400 | |
2027 and thereafter | 517 | |
Total | 1,167 | |
Unamortized premium, discount and debt issuance cost | (3) | |
| |
| |
Total | $ | 1,164 | |
The issuance of General and Refunding Mortgage Securities by Sierra Pacific is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2021, approximately $4.5 billion (based on original cost) of Sierra Pacific's property was subject to the liens of the mortgages.
(9) Income Taxes
Income tax expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current – Federal | $ | 5 | | | $ | 3 | | | $ | 19 | |
| | | | | |
Deferred – Federal | 13 | | | 12 | | | 10 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Investment tax credits | — | | | — | | | (1) | |
Total income tax expense | $ | 18 | | | $ | 15 | | | $ | 28 | |
A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (8) | | | (9) | | | — | |
| | | | | |
| | | | | |
| | | | | |
Effective income tax rate | 13 | % | | 12 | % | | 21 | % |
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 64 | | | $ | 67 | |
| | | |
| | | |
Operating and finance leases | 27 | | | 30 | |
Customer advances | 14 | | | 10 | |
Unamortized contract value | 8 | | | 2 | |
Other | 6 | | | 8 | |
Total deferred income tax assets | 119 | | | 117 | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (379) | | | (380) | |
Regulatory assets | (94) | | | (74) | |
Operating and finance leases | (27) | | | (30) | |
Other | (21) | | | (7) | |
Total deferred income tax liabilities | (521) | | | (491) | |
Net deferred income tax liability | $ | (402) | | | $ | (374) | |
| | | |
| | | |
| | | |
| | | |
| | | |
The United States Internal Revenue Service has closed its examination of NV Energy's consolidated income tax returns through December 31, 2008, and effectively settled its examination of Sierra Pacific's income tax return for the short year ended December 31, 2013, and the statute of limitations has expired for NV Energy's consolidated income tax returns through the short year ended December 19, 2013. The closure or effective settlement of examinations, or the expiration of the statute of limitations may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
(10) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific did not make any contributions to the Qualified Pension Plan for the years ended December 31, 2021, 2020 and 2019. Sierra Pacific contributed $1 million to the Non-Qualified Pension Plans for the years ended December 31, 2021, 2020 and 2019. Sierra Pacific contributed $1 million to the Other Post Retirement Plan for the year ended December 31, 2021. Sierra Pacific did not make any contributions to the Other Post Retirement Plans for the years ended December 31, 2020 and 2019. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Qualified Pension Plan - | | | |
Other non-current assets | $ | 62 | | | $ | 26 | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (7) | | | (8) | |
| | | |
Other Postretirement Plans - | | | |
Other long-term liabilities | (10) | | | (13) | |
(11) Asset Retirement Obligations
Sierra Pacific estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Sierra Pacific does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $201 million and $197 million as of December 31, 2021 and 2020, respectively.
The following table presents Sierra Pacific's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Asbestos | $ | 5 | | | $ | 5 | |
Evaporative ponds and dry ash landfills | 3 | | | 3 | |
Other | 3 | | | 3 | |
Total asset retirement obligations | $ | 11 | | | $ | 11 | |
The following table reconciles the beginning and ending balances of Sierra Pacific's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 11 | | | $ | 10 | |
| | | |
| | | |
| | | |
Accretion | — | | | 1 | |
Ending balance | $ | 11 | | | $ | 11 | |
| | | |
Reflected as - | | | |
| | | |
| | | |
Other long-term liabilities | $ | 11 | | | $ | 11 | |
Certain of Sierra Pacific's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Sierra Pacific is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Sierra Pacific's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)Risk Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 2 | | | | | $ | — | | | $ | — | | | $ | 2 | |
Commodity liabilities | — | | | | | (16) | | | (19) | | | (35) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 2 | | | | | $ | (16) | | | $ | (19) | | | $ | (33) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 9 | | | | | $ | — | | | $ | — | | | $ | 9 | |
Commodity liabilities | — | | | | | — | | | (2) | | | (2) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 9 | | | | | $ | — | | | $ | (2) | | | $ | 7 | |
(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2021 a regulatory asset of $33 million was recorded related to the net derivative liability of $33 million. As of December 31, 2020 a regulatory liability of $7 million was recorded related to the net derivative asset of $7 million.
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases | Megawatt hours | | 1 | | | — | |
Natural gas purchases | Decatherms | | 53 | | | 54 | |
| | | | | |
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $— million as of December 31, 2021 and 2020, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | |
Money market mutual funds | 10 | | | — | | | — | | | 10 | |
Investment funds | 1 | | | — | | | — | | | 1 | |
| $ | 11 | | | $ | — | | | $ | 2 | | | $ | 13 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (35) | | | $ | (35) | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | |
Money market mutual funds | 17 | | | — | | | — | | | 17 | |
| $ | 17 | | | $ | — | | | $ | 9 | | | $ | 26 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of December 31, 2021, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Sierra Pacific's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Beginning balance | | $ | 7 | | | $ | (1) | | | $ | 2 | |
Changes in fair value recognized in regulatory assets or liabilities | | (25) | | | (2) | | | (5) | |
| | | | | | |
Settlements | | (15) | | | 10 | | | 2 | |
Ending balance | | $ | (33) | | | $ | 7 | | | $ | (1) | |
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 1,164 | | | $ | 1,316 | | | $ | 1,164 | | | $ | 1,358 | |
(14) Commitments and Contingencies
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Commitments
Sierra Pacific has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2027 and | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 338 | | | $ | 227 | | | $ | 149 | | | $ | 120 | | | $ | 105 | | | $ | 1,072 | | | $ | 2,011 | |
Fuel and capacity contract commitments (not commercially operable) | 25 | | | 27 | | | 27 | | | 26 | | | 26 | | | 459 | | | 590 | |
Construction commitments | 35 | | | 497 | | | 737 | | | 76 | | | — | | | — | | | 1,345 | |
| | | | | | | | | | | | | |
Easements | 2 | | | 2 | | | 2 | | | 2 | | | 2 | | | 28 | | | 38 | |
Maintenance, service and other contracts | 7 | | | 6 | | | 6 | | | 5 | | | 1 | | | — | | | 25 | |
Total commitments | $ | 407 | | | $ | 759 | | | $ | 921 | | | $ | 229 | | | $ | 134 | | | $ | 1,559 | | | $ | 4,009 | |
Fuel and Capacity Contract Commitments
Purchased Power
Sierra Pacific has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2022 to 2046. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Sierra Pacific's lease commitments.
Ability to Issue General and Refunding Mortgage Securities
To the extent Nevada Power has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Nevada Power's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Nevada Power's indenture.
Nevada Power's indenture creates a lien on substantially all of Nevada Power's properties in Nevada. As of December 31, 2021, $9.4 billion of Nevada Power's assets were pledged. Nevada Power had the capacity to issue $3.7 billion of additional general and refunding mortgage securities as of December 31, 2021, determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Nevada Power also has the ability to release property from the lien of Nevada Power's indenture on the basis of net property additions, cash or retired bonds. To the extent Nevada Power releases property from the lien of Nevada Power's indenture, it will reduce the amount of securities issuable under the indenture.
Long-Term Debt
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
Future Uses of Cash
Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including Nevada Power's credit ratings, investors' judgment of risk associated with Nevada Power and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Electric distribution | $ | 209 | | | $ | 232 | | | $ | 184 | | | $ | 193 | | | $ | 184 | | | $ | 181 | |
Electric transmission | 24 | | | 35 | | | 57 | | | 169 | | | 206 | | | 432 | |
Solar generation | — | | | — | | | 8 | | | 95 | | | 568 | | | 602 | |
Other | 171 | | | 188 | | | 200 | | | 576 | | | 276 | | | 163 | |
Total | $ | 404 | | | $ | 455 | | | $ | 449 | | | $ | 1,033 | | | $ | 1,234 | | | $ | 1,378 | |
Nevada Power received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its IRP filings in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar generation includes growth projects consisting of three solar photovoltaic facilities. The first project is a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The final project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. The facilities located in Humboldt County will be jointly owned and operated by Nevada Power and Sierra Pacific.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
Nevada Power has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7) and AROs (refer to Note 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Nevada Power has cash requirements relating to interest payments of $1.8 billion on long-term debt, including $115 million due in 2022.
Regulatory Matters
Nevada Power is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Nevada Power's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Nevada Power is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Nevada Power's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Nevada Power has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Nevada Power's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2021, Nevada Power would have been required to post $113 million of additional collateral. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where Nevada Power operates has not had a significant impact on Nevada Power's consolidated financial results. Nevada Power operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Nevada Power is allowed to include prudent costs in its rates, including the impact of inflation after Nevada Power experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Nevada Power attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Nevada Power's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Nevada Power's Summary of Significant Accounting Policies included in Nevada Power's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $1 billion and total regulatory liabilities were $1.1 billion as of December 31, 2021. Refer to Nevada Power's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Nevada Power would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Nevada Power's results of operations.
Income Taxes
In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Nevada Power's federal, state and local income tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Nevada Power's consolidated financial results. Refer to Nevada Power's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's income taxes.
It is probable that Nevada Power will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property related basis differences and other various differences on to its customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $603 million and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $107 million as of December 31, 2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Nevada Power's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Nevada Power's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Nevada Power transacts. The following discussion addresses the significant market risks associated with Nevada Power's business activities. Nevada Power has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's contracts accounted for as derivatives.
Commodity Price Risk
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity and natural gas market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Nevada Power's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Nevada Power's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | (113) | | | $ | (93) | | | $ | (133) | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | 15 | | | $ | 19 | | | $ | 11 | |
Nevada Power's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose Nevada Power to earnings volatility. As of December 31, 2021 and 2020, a net regulatory asset of $113 million and a net regulatory liability of $15 million, respectively, was recorded related to the net derivative liability of $113 million and net derivative asset of $15 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Nevada Power is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Nevada Power's fixed-rate long-term debt does not expose Nevada Power to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Nevada Power were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Nevada Power's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Nevada Power's short- and long-term debt.
As of December 31, 2021 and 2020, Nevada Power had short-term variable-rate obligations totaling $180 million and $— million, respectively, that expose Nevada Power to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Nevada Power's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2021 and 2020.
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2021, Nevada Power's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries ("Nevada Power") as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Nevada Power as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Nevada Power's management. Our responsibility is to express an opinion on Nevada Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Nevada Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Nevada Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Nevada Power is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Nevada Power operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense, and income tax expense.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Nevada Power an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Nevada Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Nevada Power's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Nevada Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected Nevada Power's filings with the Commissions and the filings with the Commissions by intervenors that may impact Nevada Power's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 25, 2022
We have served as Nevada Power's auditor since 1987.
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 33 | | | $ | 25 | |
Trade receivables, net | 227 | | | 234 | |
Inventories | 64 | | | 69 | |
Derivative contracts | 4 | | | 26 | |
Regulatory assets | 291 | | | 48 | |
| | | |
Prepayments | 33 | | | 38 | |
Other current assets | 49 | | | 26 | |
Total current assets | 701 | | | 466 | |
| | | |
Property, plant and equipment, net | 6,891 | | | 6,701 | |
Finance lease right of use assets, net | 326 | | | 351 | |
Regulatory assets | 728 | | | 746 | |
Other assets | 106 | | | 72 | |
| | | |
Total assets | $ | 8,752 | | | $ | 8,336 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 242 | | | $ | 181 | |
Accrued interest | 32 | | | 32 | |
Accrued property, income and other taxes | 29 | | | 25 | |
Short-term debt | 180 | | | — | |
| | | |
Current portion of finance lease obligations | 26 | | | 27 | |
Regulatory liabilities | 49 | | | 50 | |
Customer deposits | 44 | | | 47 | |
Asset retirement obligation | 19 | | | 25 | |
Derivative contracts | 55 | | | 4 | |
Other current liabilities | 17 | | | 18 | |
Total current liabilities | 693 | | | 409 | |
| | | |
Long-term debt | 2,499 | | | 2,496 | |
Finance lease obligations | 310 | | | 334 | |
Regulatory liabilities | 1,100 | | | 1,163 | |
Deferred income taxes | 782 | | | 738 | |
Other long-term liabilities | 338 | | | 257 | |
Total liabilities | 5,722 | | | 5,397 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding | — | | | — | |
Additional paid-in capital | 2,308 | | | 2,308 | |
Retained earnings | 724 | | | 634 | |
Accumulated other comprehensive loss, net | (2) | | | (3) | |
Total shareholder's equity | 3,030 | | | 2,939 | |
| | | |
Total liabilities and shareholder's equity | $ | 8,752 | | | $ | 8,336 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue | $ | 2,139 | | | $ | 1,998 | | | $ | 2,148 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 939 | | | 816 | | | 943 | |
Operations and maintenance | 301 | | | 299 | | | 324 | |
Depreciation and amortization | 406 | | | 361 | | | 357 | |
Property and other taxes | 48 | | | 47 | | | 45 | |
| | | | | |
Total operating expenses | 1,694 | | | 1,523 | | | 1,669 | |
| | | | | |
Operating income | 445 | | | 475 | | | 479 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (153) | | | (162) | | | (171) | |
Allowance for borrowed funds | 3 | | | 3 | | | 3 | |
Allowance for equity funds | 7 | | | 7 | | | 5 | |
Interest and dividend income | 20 | | | 10 | | | 13 | |
Other, net | 18 | | | 9 | | | 8 | |
Total other income (expense) | (105) | | | (133) | | | (142) | |
| | | | | |
Income before income tax expense | 340 | | | 342 | | | 337 | |
Income tax expense | 37 | | | 47 | | | 73 | |
Net income | $ | 303 | | | $ | 295 | | | $ | 264 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Other | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
Balance, December 31, 2018 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 600 | | | $ | (4) | | | $ | 2,904 | |
Net income | | — | | | — | | | — | | | 264 | | | — | | | 264 | |
Dividends declared | | — | | | — | | | — | | | (371) | | | — | | | (371) | |
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 | | | — | | | 2,308 | | | 493 | | | (4) | | | 2,797 | |
Net income | | — | | | — | | | — | | | 295 | | | — | | | 295 | |
Dividends declared | | — | | | — | | | — | | | (155) | | | — | | | (155) | |
Other equity transactions | | — | | | — | | | — | | | 1 | | | 1 | | | 2 | |
Balance, December 31, 2020 | | 1,000 | | | — | | | 2,308 | | | 634 | | | (3) | | | 2,939 | |
Net income | | — | | | — | | | — | | | 303 | | | — | | | 303 | |
Dividends declared | | — | | | — | | | — | | | (213) | | | — | | | (213) | |
Other equity transactions | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 303 | | | $ | 295 | | | $ | 264 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 406 | | | 361 | | | 357 | |
Allowance for equity funds | (7) | | | (7) | | | (5) | |
Changes in regulatory assets and liabilities | (19) | | | (42) | | | 27 | |
Deferred income taxes and amortization of investment tax credits | — | | | (10) | | | (32) | |
Deferred energy | (245) | | | (44) | | | 51 | |
Amortization of deferred energy | 11 | | | (41) | | | 43 | |
Other, net | — | | | 2 | | | (5) | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | 6 | | | 45 | | | 19 | |
Inventories | 5 | | | (7) | | | 1 | |
Accrued property, income and other taxes | (18) | | | 5 | | | (13) | |
Accounts payable and other liabilities | 63 | | | (90) | | | (6) | |
Net cash flows from operating activities | 505 | | | 467 | | | 701 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (449) | | | (455) | | | (409) | |
| | | | | |
Proceeds from sale of assets | — | | | 26 | | | 2 | |
Other, net | 2 | | | — | | | — | |
Net cash flows from investing activities | (447) | | | (429) | | | (407) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | 718 | | | 495 | |
Repayments of long-term debt | — | | | (575) | | | (500) | |
Net proceeds from short-term debt | 180 | | | — | | | — | |
Dividends paid | (213) | | | (155) | | | (371) | |
Other, net | (16) | | | (15) | | | (14) | |
Net cash flows from financing activities | (49) | | | (27) | | | (390) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 9 | | | 11 | | | (96) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 36 | | | 25 | | | 121 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 45 | | | $ | 36 | | | $ | 25 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Nevada Power Company and its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Nevada Power and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Nevada Power's assessment of the collectability of amounts owed to Nevada Power by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Nevada Power primarily utilizes credit loss history. However, Nevada Power may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Nevada Power also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The changes in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 19 | | | $ | 15 | | | $ | 16 | |
Charged to operating costs and expenses, net | 13 | | | 13 | | | 12 | |
Write-offs, net | (14) | | | (9) | | | (13) | |
Ending balance | $ | 18 | | | $ | 19 | | | $ | 15 | |
Derivatives
Nevada Power employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.
For Nevada Power's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies totaling $64 million and $69 million as of December 31, 2021 and 2020. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Nevada Power capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the Public Utilities Commission of Nevada ("PUCN").
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Nevada Power's various regulatory authorities. Depreciation studies are completed by Nevada Power to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Nevada Power retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Nevada Power is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Nevada Power's AFUDC rate used during 2021 and 2020 was 7.14% and 7.43%, respectively.
Asset Retirement Obligations
Nevada Power recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Nevada Power's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
Nevada Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Nevada Power's operating and right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly.
Income Taxes
Berkshire Hathaway includes Nevada Power in its consolidated United States federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property‑related basis differences and other various differences that Nevada Power deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Nevada Power's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Nevada Power uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Nevada Power expects to be entitled in exchange for those goods or services. Nevada Power records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Nevada Power's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of amounts not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers" and revenue recognized in accordance with ASC 842, "Leases."
Revenue recognized is equal to what Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power's performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $107 million and $104 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In addition, Nevada Power has recognized contract assets of $6 million and $8 million as of December 31, 2021 and 2020, respectively, due to Nevada Power's performance on certain contracts.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.
Segment Information
Nevada Power currently has 1 segment, which includes its regulated electric utility operations.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,793 | | | $ | 3,690 | |
Transmission | 45 - 70 years | | 1,503 | | | 1,468 | |
Distribution | 20 - 65 years | | 3,920 | | | 3,771 | |
General and intangible plant | 5 - 65 years | | 836 | | | 791 | |
Utility plant | | | 10,052 | | | 9,720 | |
Accumulated depreciation and amortization | | | (3,406) | | | (3,162) | |
Utility plant, net | | | 6,646 | | | 6,558 | |
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
Plant, net | | | 6,647 | | | 6,559 | |
Construction work-in-progress | | | 244 | | | 142 | |
Property, plant and equipment, net | | | $ | 6,891 | | | $ | 6,701 | |
Almost all of Nevada Power's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Nevada Power's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2021, 2020 and 2019 was 3.2%, 3.1%, and 3.3%, respectively. Nevada Power is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2017.
Construction work-in-progress is primarily related to the construction of regulated assets.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements, Nevada Power, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Nevada Power accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Nevada Power's share of the expenses of these facilities.
The amounts shown in the table below represent Nevada Power's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Nevada | | | | | | Construction |
| Power's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Navajo Generating Station(1) | 11 | % | | $ | 5 | | | $ | 5 | | | $ | — | |
ON Line Transmission Line | 19 | | | 120 | | | 23 | | | 1 | |
Other transmission facilities | Various | | 61 | | | 32 | | | — | |
Total | | | $ | 186 | | | $ | 60 | | | $ | 1 | |
(1)Represents Nevada Power's proportionate share of capitalized asset retirement costs to retire the Navajo Generating Station, which was shut down in November 2019.
(5) Leases
The following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 10 | | | $ | 12 | |
Finance leases | 326 | | | 351 | |
Total right-of-use assets | $ | 336 | | | $ | 363 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 13 | | | $ | 15 | |
Finance leases | 336 | | | 361 | |
Total lease liabilities | $ | 349 | | | $ | 376 | |
The following table summarizes Nevada Power's lease costs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 | | |
| | | | | | | |
Variable | $ | 449 | | | $ | 434 | | | $ | 434 | | | |
Operating | 2 | | | 3 | | | 3 | | | |
Finance: | | | | | | | |
Amortization | 13 | | | 12 | | | 13 | | | |
Interest | 28 | | | 29 | | | 37 | | | |
| | | | | | | |
Total lease costs | $ | 492 | | | $ | 478 | | | $ | 487 | | | |
| | | | | | | |
Weighted-average remaining lease term (years): | | | | | | | |
Operating leases | 5.7 | | 6.5 | | 7.5 | | |
Finance leases | 28.7 | | 28.7 | | 30.6 | | |
| | | | | | | |
Weighted-average discount rate: | | | | | | | |
Operating leases | 4.5 | % | | 4.5 | % | | 4.5 | % | | |
Finance leases | 8.6 | % | | 8.6 | % | | 8.7 | % | | |
The following table summarizes Nevada Power's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 | | |
| | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | |
Operating cash flows from operating leases | $ | (3) | | | $ | (3) | | | $ | (3) | | | |
Operating cash flows from finance leases | (29) | | | (34) | | | (37) | | | |
Financing cash flows from finance leases | (16) | | | (15) | | | (14) | | | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | | | |
Operating leases | $ | — | | | $ | 1 | | | $ | — | | | |
Finance leases | 1 | | | 9 | | | 9 | | | |
Nevada Power has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 3 | | | $ | 54 | | | $ | 57 | |
2023 | 2 | | | 44 | | | 46 | |
2024 | 3 | | | 44 | | | 47 | |
2025 | 2 | | | 43 | | | 45 | |
2026 | 3 | | | 43 | | | 46 | |
Thereafter | 2 | | | 448 | | | 450 | |
Total undiscounted lease payments | 15 | | | 676 | | | 691 | |
Less - amounts representing interest | (2) | | | (340) | | | (342) | |
Lease liabilities | $ | 13 | | | $ | 336 | | | $ | 349 | |
Operating and Finance Lease Obligations
Nevada Power's lease obligation primarily consists of a transmission line, One Nevada Transmission Line ("ON Line"), which was placed in-service on December 31, 2013. Nevada Power and Sierra Pacific, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the necessary procedures to change the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved ownership percentage change from Nevada Power to Sierra Pacific. The term of the lease is 41 years with the agreement ending December 31, 2054. Total ON Line finance lease obligations of $286 million and $295 million were included on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively. See Note 2 for further discussion of Nevada Power's other lease obligations.
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. Nevada Power's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred energy costs | 1 year | | $ | 273 | | | $ | 39 | |
Decommissioning costs | 2 years | | 169 | | | 230 | |
Unrealized loss on regulated derivative contracts | 1 year | | 117 | | | 11 | |
Merger costs from 1999 merger | 23 years | | 110 | | | 115 | |
Deferred operating costs | 12 years | | 93 | | | 119 | |
Asset retirement obligations | 6 years | | 73 | | | 70 | |
ON Line deferrals | 32 years | | 42 | | | 43 | |
Legacy meters | 11 years | | 41 | | | 45 | |
Employee benefit plans(1) | 8 years | | 11 | | | 50 | |
| | | | | |
Other | Various | | 90 | | | 72 | |
Total regulatory assets | | | $ | 1,019 | | | $ | 794 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 291 | | | $ | 48 | |
Noncurrent assets | | | 728 | | | 746 | |
Total regulatory assets | | | $ | 1,019 | | | $ | 794 | |
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
Nevada Power had regulatory assets not earning a return on investment of $371 million and $288 million as of December 31, 2021 and 2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, AROs, deferred operating costs, a portion of the employee benefit plans, losses on reacquired debt and deferred energy costs.
Regulatory Liabilities
Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Nevada Power's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 603 | | | $ | 647 | |
Cost of removal(2) | 31 years | | 348 | | | 340 | |
| | | | | |
| | | | | |
| | | | | |
Other | Various | | 198 | | | 226 | |
Total regulatory liabilities | | | $ | 1,149 | | | $ | 1,213 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 49 | | | $ | 50 | |
Noncurrent liabilities | | | 1,100 | | | 1,163 | |
Total regulatory liabilities | | | $ | 1,149 | | | $ | 1,213 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Natural Disaster Protection Plan ("NDPP")
In March 2021, Nevada Power filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Nevada Power filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Nevada Power and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.
Regulatory Rate Review
In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2020, the PUCN issued a final order directing Nevada Power to continue the earning sharing mechanism subject to any modifications made to the earning sharing mechanism pursuant to an alternative rate-making ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory rate review. The new rates were effective on January 1, 2021.
Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")
EEPR was established to allow Nevada Power to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Nevada Power and approved by the PUCN in integrated resource plan proceedings. When Nevada Power's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2021, Nevada Power filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2020, including carrying charges. In August 2021, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 2020 revenue and reset the rates as filed effective October 1, 2021. The EEIR liability for Nevada Power is $8 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020.
(7)Short-term Debt and Credit Facilities
The following table summarizes Nevada Power's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | | | | | | | |
| | 2021 | | 2020 |
Credit facilities | | $ | 400 | | | $ | 400 | |
Short-term debt | | (180) | | | — | |
| | | | |
Net credit facilities | | $ | 220 | | | $ | 400 | |
Nevada Power has a $400 million secured credit facility expiring in June 2024 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which is for general corporate purposes and provide for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long‑term debt securities. As of December 31, 2021 and 2020, Nevada Power had borrowings of $180 million and $— million, respectively, outstanding under the credit facility. As of December 31, 2021, the weighted average interest rate on borrowings outstanding was 0.86%. Amounts due under Nevada Power's credit facility are collateralized by Nevada Power's general and refunding mortgage bonds. The credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2021, Nevada Power had $15 million of a fully available letter of credit issued under committed arrangements in support of certain transactions required by a third party and has provisions that automatically extend the annual expiration date for an additional year unless the issuing bank elects not to renew the letter of credit prior to the expiration date.
(8) Long-term Debt
Nevada Power's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
General and refunding mortgage securities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
3.700% Series CC, due 2029 | $ | 500 | | | $ | 497 | | | $ | 496 | |
2.400% Series DD, due 2030 | 425 | | | 422 | | | 422 | |
6.650% Series N, due 2036 | 367 | | | 359 | | | 359 | |
6.750% Series R, due 2037 | 349 | | | 346 | | | 346 | |
5.375% Series X, due 2040 | 250 | | | 248 | | | 248 | |
5.450% Series Y, due 2041 | 250 | | | 239 | | | 237 | |
3.125% Series EE, due 2050 | 300 | | | 297 | | | 297 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.875% Pollution Control Bonds Series 2017A, due 2032(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017, due 2036(1) | 40 | | | 39 | | | 39 | |
1.650% Pollution Control Bonds Series 2017B, due 2039(1) | 13 | | | 13 | | | 13 | |
| | | | | |
| | | | | |
| | | | | |
Total long-term debt | $ | 2,534 | | | $ | 2,499 | | | $ | 2,496 | |
| | | | | |
Reflected as: | | | | | |
| | | | | |
| | | | | |
Total long-term debt | | | $ | 2,499 | | | $ | 2,496 | |
(1)Subject to mandatory purchase by Nevada Power in March 2023 at which date the interest rate may be adjusted.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt for the years beginning January 1, 2022 and thereafter, are as follows (in millions):
| | | | | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
2027 and thereafter | $ | 2,534 | | | | | |
| | | | | |
Unamortized premium, discount and debt issuance cost | (35) | | | | | |
| | | | | |
| | | | | |
Total | $ | 2,499 | | | | | |
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
The issuance of General and Refunding Mortgage Securities by Nevada Power is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2021, approximately $9.4 billion (based on original cost) of Nevada Power's property was subject to the liens of the mortgages.
(9) Income Taxes
Income tax expense consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current – Federal | $ | 37 | | | $ | 57 | | | $ | 105 | |
| | | | | |
Deferred – Federal | — | | | (10) | | | (31) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Investment tax credits | — | | | — | | | (1) | |
Total income tax expense | $ | 37 | | | $ | 47 | | | $ | 73 | |
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (11) | | | (8) | | | — | |
| | | | | |
| | | | | |
Other | 1 | | | 1 | | | 1 | |
Effective income tax rate | 11 | % | | 14 | % | | 22 | % |
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 195 | | | $ | 206 | |
Operating and finance leases | 73 | | | 79 | |
Customer advances | 25 | | | 19 | |
Unamortized contract value | 25 | | | 8 | |
Other | 8 | | | 15 | |
Total deferred income tax assets | 326 | | | 327 | |
| | | |
| | | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (800) | | | (800) | |
Regulatory assets | (204) | | | (176) | |
Operating and finance leases | (70) | | | (76) | |
Other | (34) | | | (13) | |
Total deferred income tax liabilities | (1,108) | | | (1,065) | |
Net deferred income tax liability | $ | (782) | | | $ | (738) | |
| | | |
| | | |
| | | |
| | | |
| | | |
The United States Internal Revenue Service has closed its examination of NV Energy's consolidated income tax returns through December 31, 2008, and effectively settled its examination of Nevada Power's income tax return for the short year ended December 31, 2013, and the statute of limitations has expired for NV Energy's consolidated income tax returns through the short year ended December 19, 2013. The closure or effective settlement of examinations, or the expiration of the statute of limitations may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
(10) Employee Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power did not make any contributions to the Qualified Pension Plan for the years ended December 31, 2021, 2020 and 2019. Nevada Power contributed $1 million to the Non-Qualified Pension Plans for the years ended December 31, 2021, 2020 and 2019. Nevada Power did not make any contributions to the Other Postretirement Plans for the years ended December 31, 2021, 2020 and 2019. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Qualified Pension Plan - | | | |
Other non-current assets | $ | 42 | | | $ | 8 | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (8) | | | (9) | |
| | | |
Other Postretirement Plans - | | | |
Other non-current assets | 8 | | | 4 | |
| | | |
(11) Asset Retirement Obligations
Nevada Power estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Nevada Power does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $348 million and $340 million as of December 31, 2021 and 2020, respectively.
The following table presents Nevada Power's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Waste water remediation | $ | 37 | | | $ | 36 | |
Evaporative ponds and dry ash landfills | 13 | | | 13 | |
| | | |
Solar | 3 | | | 3 | |
Other | 15 | | | 20 | |
Total asset retirement obligations | $ | 68 | | | $ | 72 | |
The following table reconciles the beginning and ending balances of Nevada Power's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 72 | | | $ | 74 | |
Change in estimated costs | — | | | 9 | |
| | | |
Retirements | (6) | | | (14) | |
Accretion | 2 | | | 3 | |
Ending balance | $ | 68 | | | $ | 72 | |
| | | |
Reflected as: | | | |
Other current liabilities | $ | 19 | | | $ | 25 | |
Other long-term liabilities | 49 | | | 47 | |
| $ | 68 | | | $ | 72 | |
In 2008, Nevada Power signed an administrative order of consent as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the administrative order of consent, Nevada Power recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between Nevada Power and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station Unit No. 4, Nevada Power and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities as required under the administrative order of consent.
Certain of Nevada Power's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Nevada Power is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Management has identified legal obligations to retire generation plant assets specified in land leases for Nevada Power's jointly-owned Navajo Generating Station, retired in November 2019, and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Nevada Power's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 4 | | | | | $ | — | | | $ | — | | | $ | 4 | |
Commodity liabilities | — | | | | | (55) | | | (62) | | | (117) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 4 | | | | | $ | (55) | | | $ | (62) | | | $ | (113) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 26 | | | | | $ | — | | | $ | — | | | $ | 26 | |
Commodity liabilities | — | | | | | (3) | | | (8) | | | (11) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 26 | | | | | $ | (3) | | | $ | (8) | | | $ | 15 | |
(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2021 a regulatory asset of $113 million was recorded related to the net derivative liability of $113 million. As of December 31, 2020 a regulatory liability of $15 million was recorded related to the net derivative asset of $15 million.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases | Megawatt hours | | 1 | | | 1 | |
Natural gas purchases | Decatherms | | 119 | | | 124 | |
| | | | | |
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $6 million and $3 million as of December 31, 2021 and 2020, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) Fair Value Measurements
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
The following table presents Nevada Power's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
Money market mutual funds | 34 | | | — | | | — | | | 34 | |
Investment funds | 3 | | | — | | | — | | | 3 | |
| $ | 37 | | | $ | — | | | $ | 4 | | | $ | 41 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (117) | | | $ | (117) | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 26 | | | $ | 26 | |
Money market mutual funds | 21 | | | — | | | — | | | 21 | |
Investment funds | 2 | | | — | | | — | | | 2 | |
| $ | 23 | | | $ | — | | | $ | 26 | | | $ | 49 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (11) | | | $ | (11) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of December 31, 2021, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.
Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Nevada Power's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Beginning balance | | $ | 15 | | | $ | (8) | | | $ | 3 | |
Changes in fair value recognized in regulatory assets or liabilities | | (90) | | | (17) | | | (21) | |
| | | | | | |
Settlements | | (38) | | | 40 | | | 10 | |
Ending balance | | $ | (113) | | | $ | 15 | | | $ | (8) | |
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The following table presents the carrying value and estimated fair value of Nevada Power's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,499 | | | $ | 3,067 | | | $ | 2,496 | | | $ | 3,245 | |
(14) Commitments and Contingencies
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Senate Bill 123
In June 2013, the Nevada State Legislature passed Senate Bill 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable facilities and other generating facilities. In May 2014, Nevada Power filed its Emissions Reduction and Capacity Replacement Plan ("ERCR Plan") in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.
In compliance with SB 123, Nevada Power retired 255 MWs of coal-fueled generation in 2019 in addition to the 557 MWs of coal-fueled generation retired in 2017. Consistent with the ERCR Plan, between 2014 and 2016, Nevada Power acquired 536 MWs of natural gas generating resources, executed long-term power purchase agreements for 200 MWs of nameplate renewable energy capacity and constructed a 15-MW solar photovoltaic facility. Nevada Power has the option to acquire 35 MWs of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval.
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Commitments
Nevada Power has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 and Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 713 | | | $ | 458 | | | $ | 346 | | | $ | 348 | | | $ | 352 | | | $ | 3,250 | | | $ | 5,467 | |
Fuel and capacity contract commitments (not commercially operable) | 20 | | | 60 | | | 181 | | | 212 | | | 211 | | | 4,302 | | | 4,986 | |
Construction commitments | 141 | | | 209 | | | — | | | — | | | — | | | — | | | 350 | |
Easements | 4 | | | 5 | | | 2 | | | 2 | | | 2 | | | 52 | | | 67 | |
Maintenance, service and other contracts | 51 | | | 34 | | | 23 | | | 18 | | | 14 | | | 33 | | | 173 | |
Total commitments | $ | 929 | | | $ | 766 | | | $ | 552 | | | $ | 580 | | | $ | 579 | | | $ | 7,637 | | | $ | 11,043 | |
Fuel and Capacity Contract Commitments
Purchased Power
Nevada Power has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2026 to 2067. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Nevada Power's lease commitments.
Natural Gas
Nevada Power's gas transportation contracts expire from 2022 to 2039 and the gas supply contracts expires from 2022 to 2023.
Fuel and Capacity Contract Commitments - Not Commercially Operable
Nevada Power has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Construction Commitments
Nevada Power's construction commitments included in the table above relate to firm commitments and include costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada and certain other generating plant projects.
Easements
Nevada Power has non-cancelable easements for land. Operations and maintenance expense on non-cancelable easements totaled $4 million, $4 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Maintenance, Service and Other Contracts
Nevada Power has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2022 to 2031.
(15) Revenues from Contracts with Customers
The following table summarizes Nevada Power's Customer Revenue by customer class for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Retail: | | | | | |
Residential | $ | 1,207 | | | $ | 1,145 | | | $ | 1,141 | |
Commercial | 414 | | | 384 | | | 441 | |
Industrial | 386 | | | 345 | | | 433 | |
Other | 14 | | | 12 | | | 20 | |
Total fully bundled | 2,021 | | | 1,886 | | | 2,035 | |
Distribution only service | 22 | | | 24 | | | 31 | |
Total retail | 2,043 | | | 1,910 | | | 2,066 | |
Wholesale, transmission and other | 74 | | | 62 | | | 57 | |
Total Customer Revenue | 2,117 | | | 1,972 | | | 2,123 | |
Other revenue | 22 | | | 26 | | | 25 | |
Total revenue | $ | 2,139 | | | $ | 1,998 | | | $ | 2,148 | |
(16) Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2021 and December 31, 2020, consist of funds restricted by the PUCN for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| December 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 33 | | | $ | 25 | |
Restricted cash and cash equivalents included in other current assets | 12 | | | 11 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 45 | | | $ | 36 | |
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 115 | | | $ | 115 | | | $ | 126 | |
Income taxes paid | $ | 63 | | | $ | 50 | | | $ | 113 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 53 | | | $ | 32 | | | $ | 49 | |
(17) Related Party Transactions
Nevada Power has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Nevada Power under this agreement totaled $3 million, $2 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Kern River Gas Transmission Company, an indirect subsidiary of BHE, provided natural gas transportation and other services to Nevada Power of $52 million for the years ended December 31, 2021, 2020 and 2019. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $4 million.
Nevada Power provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $3 million, $3 million and $2 million for the years ended December 31, 2021, 2020 and 2019, respectively. There were no receivables associated with these services as of December 31, 2021 and 2020. PacifiCorp provided electricity and the sale of renewable energy credits to Nevada Power of $— million, $1 million and $— million for the years ended December 31, 2021, 2020, and 2019, respectively. There were no payables associated with these transactions as of December 31, 2021 and 2020.
Nevada Power provided electricity to Sierra Pacific of $179 million, $106 million and $84 million for the years ended December 31, 2021, 2020 and 2019, respectively. Receivables associated with these transactions were $13 million as of December 31, 2021 and 2020. Nevada Power purchased electricity from Sierra Pacific of $43 million, $34 million and $25 million for the years ended December 31, 2021, 2020 and 2019, respectively. Payables associated with these transactions were $— million and $1 million as of December 31, 2021 and 2020, respectively.
Nevada Power incurs intercompany administrative and shared facility costs with NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. Nevada Power provided services to NV Energy of $1 million, $— million and $— million for each of the years ending December 31, 2021, 2020 and 2019, respectively. NV Energy provided services to Nevada Power of $9 million for the years ending December 31, 2021, 2020 and 2019. Nevada Power provided services to Sierra Pacific of $25 million, $26 million and $26 million for the years ended December 31, 2021, 2020 and 2019, respectively. Sierra Pacific provided services to Nevada Power of $15 million, $15 million and $14 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included amounts due to NV Energy of $33 million and $28 million, respectively. There were no receivables due from NV Energy as of December 31, 2021 and 2020. As of December 31, 2021 and 2020, Nevada Power's Consolidated Balance Sheets included receivables due from Sierra Pacific of $2 million. There were no payables due to Sierra Pacific as of December 31, 2021 and 2020.
Nevada Power is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. As of December 31, 2021 and 2020 federal income taxes receivable from NV Energy were $27 million and $— million, respectively. Nevada Power made cash payments of $63 million, $50 million and $113 million for federal income taxes for the years ended December 31, 2021, 2020 and 2019, respectively.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Nevada Power and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2021 was $124 million, an increase of $13 million, or 12%, compared to 2020, primarily due to $5 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, $4 million of higher electric utility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from the residential customer class, partially offset by lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, $4 million of higher other, net, mainly due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies, $3 million of higher allowance for equity funds, mainly due to higher construction work-in-progress, $2 million of higher natural gas utility margin, mainly due to higher commercial usage, and $2 million of lower interest expense, mainly due to lower carrying charges on regulatory balances, partially offset by $3 million of higher income tax expense primarily due to higher pretax income, $2 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant in-service, and $1 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher legal expenses, offset by lower earnings sharing.
Net income for the year ended December 31, 2020 was $111 million, an increase of $8 million, or 8%, compared to 2019, primarily due to $13 million of lower income tax expense due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 1, 2020, $10 million of lower operations and maintenance expenses, primarily due to higher regulatory-directed credits, and $4 million of higher electric utility margin, partially offset by $16 million of higher depreciation and amortization, mainly due to higher plant in-service, and $3 million of lower natural gas utility margin.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Sierra Pacific's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 848 | | | $ | 738 | | | $ | 110 | | 15 | % | | $ | 738 | | | $ | 770 | | | $ | (32) | | (4) | % |
Cost of fuel and energy | | 407 | | | 301 | | | 106 | | 35 | | | 301 | | | 337 | | | (36) | | (11) | |
Electric utility margin | | 441 | | | 437 | | | 4 | | 1 | % | | 437 | | | 433 | | | 4 | | 1 | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 117 | | | 116 | | | 1 | | 1 | % | | 116 | | | 119 | | | (3) | | (3) | % |
Natural gas purchased for resale | | 61 | | | 62 | | | (1) | | (2) | | | 62 | | | 62 | | | — | | — | |
Natural gas utility margin | | 56 | | | 54 | | | 2 | | 4 | % | | 54 | | | 57 | | | (3) | | (5) | % |
| | | | | | | | | | | | | | |
Utility margin | | 497 | | | 491 | | | 6 | | 1 | % | | 491 | | | 490 | | | 1 | | — | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | 163 | | | 162 | | | 1 | | 1 | % | | 162 | | | 172 | | | (10) | | (6) | % |
Depreciation and amortization | | 143 | | | 141 | | | 2 | | 1 | | | 141 | | | 125 | | | 16 | | 13 | |
Property and other taxes | | 24 | | | 23 | | | 1 | | 4 | | | 23 | | | 22 | | | 1 | | 5 | |
Operating income | | $ | 167 | | | $ | 165 | | | $ | 2 | | 1 | % | | $ | 165 | | | $ | 171 | | | $ | (6) | | (4) | % |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 848 | | | $ | 738 | | | $ | 110 | | 15 | % | | $ | 738 | | | $ | 770 | | | $ | (32) | | (4) | % |
Cost of fuel and energy | | 407 | | | 301 | | | 106 | | 35 | | | 301 | | | 337 | | | (36) | | (11) | |
Utility margin | | $ | 441 | | | $ | 437 | | | $ | 4 | | 1 | % | | $ | 437 | | | $ | 433 | | | $ | 4 | | 1 | % |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 2,769 | | | 2,672 | | | 97 | | 4 | % | | 2,672 | | | 2,491 | | | 181 | | 7 | % |
Commercial | | 3,056 | | | 2,977 | | | 79 | | 3 | | | 2,977 | | | 2,973 | | | 4 | | — | |
Industrial | | 3,716 | | | 3,544 | | | 172 | | 5 | | | 3,544 | | | 3,716 | | | (172) | | (5) | |
Other | | 15 | | | 15 | | | — | | — | | | 15 | | | 16 | | | (1) | | (6) | |
Total fully bundled(1) | | 9,556 | | | 9,208 | | | 348 | | 4 | | | 9,208 | | | 9,196 | | | 12 | | — | |
Distribution only service | | 1,639 | | | 1,670 | | | (31) | | (2) | | | 1,670 | | | 1,629 | | | 41 | | 3 | |
Total retail | | 11,195 | | | 10,878 | | | 317 | | 3 | | | 10,878 | | | 10,825 | | | 53 | | — | |
Wholesale | | 656 | | | 548 | | | 108 | | 20 | | | 548 | | | 662 | | | (114) | | (17) | |
Total GWhs sold | | 11,851 | | | 11,426 | | | 425 | | 4 | % | | 11,426 | | | 11,487 | | | (61) | | (1) | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 365 | | | 359 | | | 6 | | 2 | % | | 359 | | | 352 | | | 7 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 81.77 | | | $ | 73.89 | | | $ | 7.88 | | 11 | % | | $ | 73.89 | | | $ | 76.72 | | | $ | (2.83) | | (4) | % |
Wholesale | | $ | 58.14 | | | $ | 52.52 | | | $ | 5.62 | | 11 | % | | $ | 52.52 | | | $ | 48.54 | | | $ | 3.98 | | 8 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 4,494 | | | 4,477 | | | 17 | | — | % | | 4,477 | | | 4,728 | | | (251) | | (5) | % |
Cooling degree days | | 1,366 | | | 1,176 | | | 190 | | 16 | % | | 1,176 | | | 1,107 | | | 69 | | 6 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 4,712 | | | 5,219 | | | (507) | | (10) | % | | 5,219 | | | 4,891 | | | 328 | | 7 | % |
Coal | | 1,220 | | | 855 | | | 365 | | 43 | | | 855 | | | 1,205 | | | (350) | | (29) | |
Renewables(4) | | 31 | | | 37 | | | (6) | | (16) | | | 37 | | | 37 | | | — | | — | |
Total energy generated | | 5,963 | | | 6,111 | | | (148) | | (2) | | | 6,111 | | | 6,133 | | | (22) | | — | |
Energy purchased | | 4,960 | | | 4,753 | | | 207 | | 4 | | | 4,753 | | | 4,466 | | | 287 | | 6 | |
Total | | 10,923 | | | 10,864 | | | 59 | | 1 | % | | 10,864 | | | 10,599 | | | 265 | | 3 | % |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(5): | | | | | | | | | | | | | | |
Energy generated | | $ | 28.84 | | | $ | 20.12 | | | $ | 8.72 | | 43 | % | | $ | 20.12 | | | $ | 26.29 | | | $ | (6.17) | | (23) | % |
Energy purchased | | $ | 47.39 | | | $ | 37.46 | | | $ | 9.93 | | 27 | % | | $ | 37.46 | | | $ | 39.39 | | | $ | (1.93) | | (5) | % |
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 2, 10 and - GWhs of coal and 6, 31 and - GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2021, 2020 and 2019, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) Includes the Fort Churchill Solar Array which was under lease by Sierra Pacific until it was acquired in December 2021.
(5) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 117 | | | $ | 116 | | | $ | 1 | | 1 | % | | $ | 116 | | | $ | 119 | | | $ | (3) | | (3) | % |
Natural gas purchased for resale | | 61 | | | 62 | | | (1) | | (2) | | | 62 | | | 62 | | | — | | — | |
Utility margin | | $ | 56 | | | $ | 54 | | | $ | 2 | | 4 | % | | $ | 54 | | | $ | 57 | | | $ | (3) | | (5) | % |
| | | | | | | | | | | | | | |
Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 10,662 | | | 10,452 | | | 210 | | 2 | % | | 10,452 | | | 11,311 | | | (859) | | (8) | % |
Commercial | | 5,524 | | | 5,148 | | | 376 | | 7 | | | 5,148 | | | 5,783 | | | (635) | | (11) | |
Industrial | | 1,981 | | | 1,826 | | | 155 | | 8 | | | 1,826 | | | 1,971 | | | (145) | | (7) | |
Total retail | | 18,167 | | | 17,426 | | | 741 | | 4 | % | | 17,426 | | | 19,065 | | | (1,639) | | (9) | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 177 | | | 174 | | | 3 | | 2 | % | | 174 | | | 170 | | | 4 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | $ | 6.44 | | | $ | 6.66 | | | $ | (0.22) | | (3) | % | | $ | 6.66 | | | $ | 6.24 | | | $ | 0.42 | | 7 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 4,494 | | | 4,477 | | | 17 | | — | % | | 4,477 | | | 4,728 | | | (251) | | (5) | % |
| | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | $ | 3.36 | | | $ | 3.56 | | | $ | (0.20) | | (6) | % | | $ | 3.56 | | | $ | 3.25 | | | $ | 0.31 | | 9 | % |
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Electric utility margin increased $4 million, or 1%, for 2021 compared to 2020 primarily due to:
•$10 million of higher electric retail utility margin primarily due to higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.9% primarily due to an increase in the average number of customers, favorable changes in customer usage patterns and the favorable impact of weather, and
•$3 million of higher transmission and wholesale revenue.
The increase in electric utility margin was offset by:
•$3 million in lower revenue recognized due to a favorable regulatory decision in 2020;
•$3 million due to an adjustment to regulatory-related revenue deferrals; and
•$2 million due to lower energy efficiency program costs (offset in operations and maintenance expense).
Natural gas utility margin increased $2 million, or 4%, for 2021 compared to 2020 primarily due to favorable changes in customer usage patterns.
Operations and maintenance increased $1 million, or 1%, for 2021 compared to 2020 primarily due to higher plant operations and maintenance expenses and higher legal expenses, offset by lower earnings sharing and lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $2 million, or 1%, for 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in-service.
Interest expense decreased $2 million, or 4%, for 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances.
Allowance for equity funds increased$3 million, or 75%, for 2021 compared to 2020 primarily due to higher construction work-in-progress.
Interest and dividend income increased $5 million for 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $4 million, or 57%, for 2021 compared to 2020 primarily due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies.
Income tax expense increased $3 million, or 20%, for 2021 compared to 2020 primarily due to higher pretax income. The effective tax rate was 13% in 2021 and 12% in 2020.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Electric utility margin increased $4 million, or 1%, for 2020 compared to 2019 primarily due to:
•$4 million in higher residential customer volumes from the favorable impact of weather;
•$3 million due to higher energy efficiency program costs (offset in operations and maintenance expense); and
•$2 million of residential customer growth.
The increase in electric utility margin was offset by:
•$4 million of lower transmission and wholesale revenue; and
•$1 million of higher revenue reductions related to customer service agreements.
Natural gas utility margin decreased $3 million, or 5%, for 2020 compared to 2019 primarily due to lower customer volumes mainly from the unfavorable impacts of weather.
Operations and maintenance decreased $10 million, or 6%, for 2020 compared to 2019 primarily due to higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) of $9 million and lower plant operations and maintenance expenses, offset by lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019 and higher energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $16 million, or 13%, for 2020 compared to 2019 primarily due to higher plant placed in-service and higher depreciation expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Other income (expense) is favorable $1 million, or 3%, for 2020 compared to 2019 primarily due to lower pension costs, partially offset by higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Income tax expense decreased $13 million, or 46%, for 2020 compared to 2019. The effective tax rate was 12% in 2020 and 21% in 2019 and decreased due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 1, 2020.
Liquidity and Capital Resources
As of December 31, 2021, Sierra Pacific's total net liquidity was $101 million as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 10 | |
| | |
Credit facilities(1) | | 250 | |
Less - | | |
Short-term debt | | (159) | |
| | |
Net credit facilities | | 91 | |
| | |
Total net liquidity | | $ | 101 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 |
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Sierra Pacific's credit facility.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $183 million and $190 million, respectively. The change was primarily due to the timing of payments for fuel and energy costs, partially offset by higher collections from customers, the timing of payments for operating costs, lower inventory purchases and increased collections of customer advances.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $190 million and $237 million, respectively. The change was primarily due to lower collections from customers, higher inventory purchases, the timing of payments for operating costs and higher payments for fuel and energy costs, partially offset by lower payments for income taxes.
The timing of Sierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(300) million and $(246) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $(246) million and $(247) million, respectively. The change was primarily due to decreased capital expenditures, partially offset by expenditures related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the years ended December 31, 2021 and 2020 were $107 million and $50 million, respectively. The change was primarily due to higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the issuance of long-term debt.
Net cash flows from financing activities for the years ended December 31, 2020 and 2019 were $50 million and $(34) million, respectively. The change was primarily due to lower payments to repurchase long-term debt, higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the re-offering of previously repurchased long-term debt.
Ability to Issue Debt
Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2021, Sierra Pacific has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Sierra Pacific's $250 million secured credit facility) does not exceed $1.6 billion as measured at the end of each calendar quarter. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of December 31, 2021. In addition, certain financing agreements contain covenants which are currently suspended as Sierra Pacific's senior secured debt is rated investment grade. However, if Sierra Pacific's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Sierra Pacific would be subject to limitations under these covenants.
In January 2022, the PUCN approved Sierra Pacific's request to increase its financing authority for debt securities to not exceed $1.9 billion as measured at the end of each calendar quarter. Additionally, the PUCN authorized Sierra Pacific to issue common and preferred stock so long as the total amounts outstanding do not exceed $2.2 billion and $500 million, respectively, at the end of each calendar quarter.
Ability to Issue General and Refunding Mortgage Securities
To the extent Sierra Pacific has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Sierra Pacific's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Sierra Pacific's indenture.
Sierra Pacific's indenture creates a lien on substantially all of Sierra Pacific's properties in Nevada. As of December 31, 2018, $4.12021, $4.5 billion of Sierra Pacific's assets were pledged. Sierra Pacific had the capacity to issue $1.4$1.7 billion of additional general and refunding mortgage securities as of December 31, 20182021 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Sierra Pacific also has the ability to release property from the lien of Sierra Pacific's indenture on the basis of net property additions, cash or retired bonds. To the extent Sierra Pacific releases property from the lien of Sierra Pacific's indenture, it will reduce the amount of securities issuable under the indenture.
Common Shareholder's Equity
In January 2022, Sierra Pacific received a capital contribution of $130 million from NV Energy, Inc.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including Sierra Pacific's credit ratings, investors' judgment of risk associated with Sierra Pacific and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| | | | | | | | | | | |
Electric distribution | $ | 156 | | | $ | 128 | | | $ | 96 | | | $ | 122 | | | $ | 129 | | | $ | 112 | |
Electric transmission | 17 | | | 60 | | | 77 | | | 164 | | | 242 | | | 326 | |
Solar generation | — | | | — | | | 17 | | | 1 | | | 134 | | | 197 | |
Other | 72 | | | 58 | | | 110 | | | 160 | | | 100 | | | 74 | |
Total | $ | 245 | | | $ | 246 | | | $ | 300 | | | $ | 447 | | | $ | 605 | | | $ | 709 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecasted |
| 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| | | | | | | | | | | |
Distribution | $ | 115 |
| | $ | 88 |
| | $ | 162 |
| | $ | 149 |
| | $ | 108 |
| | 101 |
|
Transmission system investment | 12 |
| | 12 |
| | 5 |
| | 36 |
| | 19 |
| | 30 |
|
Other | 67 |
| | 86 |
| | 34 |
| | 64 |
| | 39 |
| | 50 |
|
Total | $ | 194 |
| | $ | 186 |
| | $ | 201 |
| | $ | 249 |
| | $ | 166 |
| | $ | 181 |
|
Sierra Pacific received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its latest IRP filing in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include investments thatthe following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to operating projects thatthe Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission distribution, generation and other infrastructure needed to serve existing and expected demand.
•Solar generation includes growth projects consisting of two solar photovoltaic facilities. The first project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. Both facilities will be jointly owned and operated by Nevada Power and Sierra Pacific.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Contractual Obligations
Material Cash Requirements
Sierra Pacific has contractual cash obligationsrequirements that may affect its consolidated financial condition. The following table summarizes Sierra Pacific's material contractual cash obligations as of December 31, 2018 (in millions):
|
| | | | | | | | | | | | | | | | | | | |
| Payments Due by Periods |
| 2019 | | 2020 - 2021 | | 2022 - 2023 | | 2024 and Thereafter | | Total |
Long-term debt | $ | — |
| | $ | — |
| | $ | 250 |
| | $ | 871 |
| | $ | 1,121 |
|
Interest payments on long-term debt(1) | 39 |
| | 81 |
| | 81 |
| | 311 |
| | 512 |
|
Capital leases, including interest(2) | 4 |
| | 5 |
| | 4 |
| | 11 |
| | 24 |
|
ON Line financial lease, including interest(2) | 2 |
| | 4 |
| | 4 |
| | 36 |
| | 46 |
|
Fuel and capacity contract commitments(1) | 204 |
| | 271 |
| | 142 |
| | 502 |
| | 1,119 |
|
Fuel and capacity contract commitments (not commercially operable)(1) | 8 |
| | 44 |
| | 116 |
| | 1,394 |
| | 1,562 |
|
Operating leases and easements(1) | 4 |
| | 8 |
| | 5 |
| | 56 |
| | 73 |
|
Asset retirement obligations | — |
| | — |
| | — |
| | 14 |
| | 14 |
|
Maintenance, service and other contracts(1) | 8 |
| | 13 |
| | 8 |
| | 1 |
| | 30 |
|
Total contractual cash obligations | $ | 269 |
| | $ | 426 |
| | $ | 610 |
| | $ | 3,196 |
| | $ | 4,501 |
|
| |
(1) | Not reflected on the Balance Sheets. |
| |
(2) | Interest is not reflected on the Balance Sheets. |
Sierra Pacific has other types of commitmentscondition that arise primarily from unused lines of credit, letters of credit or relatelong- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (Liquidity(refer to Liquidity and Capital Resources included within this Item 77) and AROs (refer to Note 6), uncertain tax positions (Note 9) and asset retirement obligations (Note 11), which have not been included in the above table because the amount and timing of the cash payments are not certain.. Refer where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K10-K for additional information.
Sierra Pacific has cash requirements relating to interest payments of $411 million on long-term debt, including $41 million due in 2022.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussioninformation regarding Sierra Pacific's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Sierra Pacific is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Sierra Pacific's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Sierra Pacific has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Sierra Pacific's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2018,2021, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2018,2021, Sierra Pacific would have been required to post $14$18 million of additional collateral. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where Sierra Pacific operates has not had a significant impact on Sierra Pacific's financial results. Sierra Pacific operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Sierra Pacific is allowed to include prudent costs in its rates, including the impact of inflation after Sierra Pacific experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Sierra Pacific attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Sierra Pacific, refer to Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Sierra Pacific's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Sierra Pacific's Summary of Significant Accounting Policies included in Sierra Pacific's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Sierra Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss).AOCI. Total regulatory assets were $321$440 million and total regulatory liabilities were $509$463 million as of December 31, 2018.2021. Refer to Sierra Pacific's Note 56 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2018,2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Sierra Pacific would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Sierra Pacific's results of operations.
Income Taxes
In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local income tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Sierra Pacific's financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Statements of Operations. Refer to Sierra Pacific's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's income taxes.
It is probable that Sierra Pacific is probable towill pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to its customers. As of December 31, 2018,2021, these amounts were recognized as a net regulatory liability of $270$234 million and will be included in regulated rates when the temporary differences reverse.
Revenue Recognition - Unbilled Revenue
Revenue is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $57$78 million as of December 31, 2018.2021. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Sierra Pacific's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Sierra Pacific's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Sierra Pacific transacts. The following discussion addresses the significant market risks associated with Sierra Pacific's business activities. Sierra Pacific has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's contracts accounted for as derivatives.
Commodity Price Risk
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Sierra Pacific's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Sierra Pacific's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
| | | | | | | | | | | | | | | | | |
| Fair Value - | | Estimated Fair Value after |
| Net Asset | | Hypothetical Change in Price |
| (Liability) | | 10% increase | | 10% decrease |
As of December 31, 2021: | | | | | |
Total commodity derivative contracts | $ | (33) | | | $ | (26) | | | $ | (40) | |
| | | | | |
As of December 31, 2020: | | | | | |
Total commodity derivative contracts | $ | 7 | | | $ | 8 | | | $ | 6 | |
Sierra Pacific's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose Sierra Pacific to earnings volatility. As of December 31, 2021 and 2020, a net regulatory asset of $33 million and net regulatory liability of $7 million, respectively, was recorded related to the net derivative liability of $33 million and net derivative asset of $7 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Sierra Pacific is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Sierra Pacific's fixed-rate long-term debt does not expose Sierra Pacific to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Sierra Pacific were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Sierra Pacific's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 67 and 78 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Sierra Pacific's short- and long-term debt.
As of December 31, 20182021 and 2017,2020, Sierra Pacific had short- and long-termshort-term variable-rate obligations totaling $80$159 million and $45 million, respectively, that expose Sierra Pacific to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Sierra Pacific's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 20182021 and 2017.2020.
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2018,2021, Sierra Pacific's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of December 31, 20182021 and 2017,2020, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2018,2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sierra Pacific as of December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Sierra Pacific's management. Our responsibility is to express an opinion on Sierra Pacific's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Sierra Pacific is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Sierra Pacific's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Sierra Pacific is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Sierra Pacific operates. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets and liabilities; deferred income taxes; operating revenue; operations and maintenance expense; depreciation and amortization expense, and income tax expense.
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Sierra Pacific an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Sierra Pacific Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Sierra Pacific's ability to recover its costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Sierra Pacific's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected Sierra Pacific's filings with the Commissions and the filings with the Commissions by intervenors that may impact Sierra Pacific's future rates, for any evidence that might contradict management's assertions.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
February 22, 201925, 2022
We have served as Sierra Pacific's auditor since 1996.
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 10 | | | $ | 19 | |
Trade receivables, net | 128 | | | 97 | |
| | | |
Inventories | 65 | | | 77 | |
Regulatory assets | 177 | | | 67 | |
| | | |
Other current assets | 35 | | | 45 | |
Total current assets | 415 | | | 305 | |
| | | |
Property, plant and equipment, net | 3,340 | | | 3,164 | |
Regulatory assets | 263 | | | 267 | |
Other assets | 205 | | | 183 | |
| | | |
Total assets | $ | 4,223 | | | $ | 3,919 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 147 | | | $ | 108 | |
Accrued interest | 14 | | | 14 | |
Accrued property, income and other taxes | 16 | | | 14 | |
Short-term debt | 159 | | | 45 | |
| | | |
Regulatory liabilities | 19 | | | 34 | |
Customer deposits | 15 | | | 15 | |
Other current liabilities | 44 | | | 25 | |
Total current liabilities | 414 | | | 255 | |
| | | |
Long-term debt | 1,164 | | | 1,164 | |
Finance lease obligations | 106 | | | 121 | |
Regulatory liabilities | 444 | | | 463 | |
Deferred income taxes | 402 | | | 374 | |
Other long-term liabilities | 158 | | | 131 | |
Total liabilities | 2,688 | | | 2,508 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | |
Additional paid-in capital | 1,111 | | | 1,111 | |
Retained earnings | 425 | | | 301 | |
Accumulated other comprehensive loss, net | (1) | | | (1) | |
Total shareholder's equity | 1,535 | | | 1,411 | |
| | | |
Total liabilities and shareholder's equity | $ | 4,223 | | | $ | 3,919 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
ASSETS |
| | | |
Current assets: | | | |
Cash and cash equivalents | $ | 71 |
| | $ | 4 |
|
Accounts receivable, net | 109 |
| | 112 |
|
Inventories | 52 |
| | 49 |
|
Regulatory assets | 7 |
| | 32 |
|
Other current assets | 24 |
| | 17 |
|
Total current assets | 263 |
| | 214 |
|
| | | |
Property, plant and equipment, net | 2,984 |
| | 2,892 |
|
Regulatory assets | 314 |
| | 300 |
|
Other assets | 8 |
| | 7 |
|
| | | |
Total assets | $ | 3,569 |
| | $ | 3,413 |
|
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 116 |
| | $ | 92 |
|
Accrued interest | 13 |
| | 14 |
|
Accrued property, income and other taxes | 14 |
| | 10 |
|
Regulatory liabilities | 18 |
| | 19 |
|
Current portion of long-term debt and financial and capital lease obligations | 3 |
| | 2 |
|
Customer deposits | 18 |
| | 15 |
|
Other current liabilities | 15 |
| | 12 |
|
Total current liabilities | 197 |
| | 164 |
|
| | | |
Long-term debt and financial and capital lease obligations | 1,155 |
| | 1,152 |
|
Regulatory liabilities | 491 |
| | 481 |
|
Deferred income taxes | 331 |
| | 330 |
|
Other long-term liabilities | 131 |
| | 114 |
|
Total liabilities | 2,305 |
| | 2,241 |
|
| | | |
Commitments and contingencies (Note 12) | | | |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — |
| | — |
|
Other paid-in capital | 1,111 |
| | 1,111 |
|
Retained earnings (accumulated deficit) | 153 |
| | 62 |
|
Accumulated other comprehensive loss, net | — |
| | (1 | ) |
Total shareholder's equity | 1,264 |
| | 1,172 |
|
| | | |
Total liabilities and shareholder's equity | $ | 3,569 |
| | $ | 3,413 |
|
| | | |
The accompanying notes are an integral part of the financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating revenue: | | | | | |
Regulated electric | $ | 848 | | | $ | 738 | | | $ | 770 | |
Regulated natural gas | 117 | | | 116 | | | 119 | |
Total operating revenue | 965 | | | 854 | | | 889 | |
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 407 | | | 301 | | | 337 | |
Cost of natural gas purchased for resale | 61 | | | 62 | | | 62 | |
Operations and maintenance | 163 | | | 162 | | | 172 | |
Depreciation and amortization | 143 | | | 141 | | | 125 | |
Property and other taxes | 24 | | | 23 | | | 22 | |
| | | | | |
Total operating expenses | 798 | | | 689 | | | 718 | |
| | | | | |
Operating income | 167 | | | 165 | | | 171 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (54) | | | (56) | | | (48) | |
Allowance for borrowed funds | 2 | | | 2 | | | 1 | |
Allowance for equity funds | 7 | | | 4 | | | 3 | |
Interest and dividend income | 9 | | | 4 | | | 3 | |
Other, net | 11 | | | 7 | | | 1 | |
Total other income (expense) | (25) | | | (39) | | | (40) | |
| | | | | |
Income before income tax expense | 142 | | | 126 | | | 131 | |
Income tax expense | 18 | | | 15 | | | 28 | |
Net income | $ | 124 | | | $ | 111 | | | $ | 103 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Operating revenue: | | | | | |
Electric | $ | 752 |
| | $ | 713 |
| | $ | 702 |
|
Natural gas | 103 |
| | 99 |
| | 110 |
|
Total operating revenue | 855 |
| | 812 |
| | 812 |
|
| | | | | |
Operating costs and expenses: | | | | | |
Cost of fuel, energy and capacity | 322 |
| | 268 |
| | 265 |
|
Natural gas purchased for resale | 49 |
| | 42 |
| | 55 |
|
Operations and maintenance | 190 |
| | 167 |
| | 169 |
|
Depreciation and amortization | 119 |
| | 114 |
| | 118 |
|
Property and other taxes | 23 |
| | 24 |
| | 24 |
|
Total operating costs and expenses | 703 |
| | 615 |
| | 631 |
|
| | | | | |
Operating income | 152 |
| | 197 |
| | 181 |
|
| | | | | |
Other income (expense): | | | | | |
Interest expense | (44 | ) | | (43 | ) | | (54 | ) |
Allowance for borrowed funds | 1 |
| | 2 |
| | 4 |
|
Allowance for equity funds | 4 |
| | 3 |
| | (1 | ) |
Other, net | 9 |
| | 5 |
| | 3 |
|
Total other income (expense) | (30 | ) | | (33 | ) | | (48 | ) |
| | | | | |
Income before income tax expense | 122 |
| | 164 |
| | 133 |
|
Income tax expense | 30 |
| | 55 |
| | 49 |
|
Net income | $ | 92 |
| | $ | 109 |
| | $ | 84 |
|
| | | | | |
The accompanying notes are an integral part of these financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Retained | | Accumulated | | |
| | | | | | Other | | Earnings | | Other | | Total |
| | Common Stock | | Paid-in | | (Accumulated | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Deficit) | | Loss, Net | | Equity |
Balance, December 31, 2018 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 153 | | | $ | — | | | $ | 1,264 | |
Net income | | — | | | — | | | — | | | 103 | | | — | | | 103 | |
Dividends declared | | — | | | — | | | — | | | (46) | | | — | | | (46) | |
Other equity transactions | | — | | | — | | | — | | | — | | | (1) | | | (1) | |
Balance, December 31, 2019 | | 1,000 | | | — | | | 1,111 | | | 210 | | | (1) | | | 1,320 | |
Net income | | — | | | — | | | — | | | 111 | | | — | | | 111 | |
Dividends declared | | — | | | — | | | — | | | (20) | | | — | | | (20) | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | — | | | 1,111 | | | 301 | | | (1) | | | 1,411 | |
Net income | | — | | | — | | | — | | | 124 | | | — | | | 124 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Retained | | Accumulated | | |
| | | | | | Other | | Earnings | | Other | | Total |
| | Common Stock | | Paid-in | | (Accumulated | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Deficit) | | Loss, Net | | Equity |
Balance, December 31, 2015 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | (35 | ) | | $ | — |
| | $ | 1,076 |
|
Net income | | — |
| | — |
| | — |
| | 84 |
| | — |
| | 84 |
|
Dividends declared | | — |
| | — |
| | — |
| | (51 | ) | | — |
| | (51 | ) |
Other equity transactions | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
Balance, December 31, 2016 | | 1,000 |
| | — |
| | 1,111 |
| | (2 | ) | | (1 | ) | | 1,108 |
|
Net income | | — |
| | — |
| | — |
| | 109 |
| | — |
| | 109 |
|
Dividends declared | | — |
| | — |
| | — |
| | (45 | ) | | — |
| | (45 | ) |
Balance, December 31, 2017 | | 1,000 |
| | — |
| | 1,111 |
| | 62 |
| | (1 | ) | | 1,172 |
|
Net income | | — |
| | — |
| | — |
| | 92 |
| | — |
| | 92 |
|
Other equity transactions | | — |
| | — |
| | — |
| | (1 | ) | | 1 |
| | — |
|
Balance, December 31, 2018 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 153 |
| | $ | — |
| | $ | 1,264 |
|
| | | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 124 | | | $ | 111 | | | $ | 103 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
| | | | | |
Depreciation and amortization | 143 | | | 141 | | | 125 | |
Allowance for equity funds | (7) | | | (4) | | | (3) | |
Changes in regulatory assets and liabilities | (39) | | | (33) | | | 25 | |
Deferred income taxes and amortization of investment tax credits | 13 | | | 12 | | | 9 | |
Deferred energy | (116) | | | (17) | | | 15 | |
Amortization of deferred energy | 29 | | | (14) | | | (2) | |
Other, net | (1) | | | (2) | | | — | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | (27) | | | (81) | | | (6) | |
Inventories | 12 | | | (19) | | | (5) | |
Accrued property, income and other taxes | 9 | | | 9 | | | (16) | |
Accounts payable and other liabilities | 43 | | | 87 | | | (8) | |
Net cash flows from operating activities | 183 | | | 190 | | | 237 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (300) | | | (246) | | | (248) | |
| | | | | |
Other, net | — | | | — | | | 1 | |
Net cash flows from investing activities | (300) | | | (246) | | | (247) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | 30 | | | 125 | |
Repayments of long-term debt | — | | | — | | | (109) | |
Net proceeds from short-term debt | 114 | | | 45 | | | — | |
Dividends paid | — | | | (20) | | | (46) | |
Other, net | (7) | | | (5) | | | (4) | |
Net cash flows from financing activities | 107 | | | 50 | | | (34) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (10) | | | (6) | | | (44) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 26 | | | 32 | | | 76 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 16 | | | $ | 26 | | | $ | 32 | |
| | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Cash flows from operating activities: | | | | | |
Net income | $ | 92 |
| | $ | 109 |
| | $ | 84 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
Loss on nonrecurring items | — |
| | — |
| | 5 |
|
Depreciation and amortization | 119 |
| | 114 |
| | 118 |
|
Allowance for equity funds | (4 | ) | | (4 | ) | | 1 |
|
Deferred income taxes and amortization of investment tax credits | 7 |
| | 55 |
| | 49 |
|
Changes in regulatory assets and liabilities | 42 |
| | 17 |
| | (17 | ) |
Deferred energy | 9 |
| | (20 | ) | | 53 |
|
Amortization of deferred energy | (10 | ) | | (47 | ) | | (54 | ) |
Other, net | — |
| | (4 | ) | | — |
|
Changes in other operating assets and liabilities: | | | | | |
Accounts receivable and other assets | 3 |
| | 4 |
| | 7 |
|
Inventories | (4 | ) | | (3 | ) | | (6 | ) |
Accrued property, income and other taxes | 3 |
| | 1 |
| | (3 | ) |
Accounts payable and other liabilities | 18 |
| | (41 | ) | | 6 |
|
Net cash flows from operating activities | 275 |
| | 181 |
| | 243 |
|
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (205 | ) | | (186 | ) | | (194 | ) |
Net cash flows from investing activities | (205 | ) | | (186 | ) | | (194 | ) |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from issuance of long-term debt | — |
| | — |
| | 1,089 |
|
Repayments of long-term debt and financial and capital lease obligations | (2 | ) | | (2 | ) | | (1,138 | ) |
Dividends paid | — |
| | (45 | ) | | (51 | ) |
Net cash flows from financing activities | (2 | ) | | (47 | ) | | (100 | ) |
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 68 |
| | (52 | ) | | (51 | ) |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 8 |
| | 60 |
| | 111 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 76 |
| | $ | 8 |
| | $ | 60 |
|
| | | | | |
The accompanying notes are an integral part of these financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Presentation
The Consolidated Financial Statements include the accounts of Sierra Pacific and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2018, 20172021, 2020 and 2016.2019.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Sierra Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.
Allowance for Doubtful AccountsCredit Losses
Accounts receivableTrade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts.credit losses. The allowance for doubtful accountscredit losses is based on Sierra Pacific's assessment of the collectibilitycollectability of amounts owed to Sierra Pacific by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Sierra Pacific primarily utilizes credit loss history. However, Sierra Pacific may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Sierra Pacific also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The changechanges in the balance of the allowance for doubtful accounts,credit losses, which is included in accounts receivable,trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | 2018 | | 2017 | | 2016 | | 2021 | | 2020 | | 2019 |
Beginning balance | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| Beginning balance | $ | 2 | | | $ | 2 | | | $ | 2 | |
Charged to operating costs and expenses, net | 1 |
| | 2 |
| | 2 |
| Charged to operating costs and expenses, net | 2 | | | 2 | | | 1 | |
Write-offs, net | (1 | ) | | (2 | ) | | (1 | ) | Write-offs, net | (3) | | | (2) | | | (1) | |
Ending balance | $ | 2 |
| | $ | 2 |
| | $ | 2 |
| Ending balance | $ | 1 | | | $ | 2 | | | $ | 2 | |
Derivatives
Sierra Pacific employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Consolidated Statements of Operations.
For Sierra Pacific's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies totaling $44$62 million and $42$67 million as of December 31, 20182021 and 2017,2020, respectively, and fuel, which includes coal stock, stored natural gas and fuel oil, totaling $8$3 million and $7$10 million as of December 31, 20182021 and 2017,2020, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Sierra Pacific capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Sierra Pacific's various regulatory authorities. Depreciation studies are completed by Sierra Pacific to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Sierra Pacific retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Sierra Pacific is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Sierra Pacific's AFUDC rate used during 20182021 and 20172020 was 6.65%6.75% for electric, 5.74% and 5.63%5.75% for natural gas respectively, and 6.55%6.65% for common facilities.
Asset Retirement Obligations
Sierra Pacific recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Sierra Pacific's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2018,2021, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
Leases
Sierra Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the option. Sierra Pacific's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Sierra Pacific's operating and finance right-of-use assets are recorded in other assets and the operating and current finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Income Taxes
Berkshire Hathaway includes Sierra Pacific in its consolidated United States federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimatedenacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that Sierra Pacific deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local incomeunrecognized tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income taxbenefits are primarily included in other long-term liabilities that may result from these examinations, if any, is not expected to have a material impact on Sierra Pacific's financial results.the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Sierra Pacific uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Sierra Pacific expects to be entitled in exchange for those goods or services. Sierra Pacific records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Sierra Pacific's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 840,842, "Leases" and amounts not considered Customer Revenue within Accounting Standards Codification ("ASC")ASC 606, "Revenue from Contracts with Customers".Customers."
Revenue recognized is equal to what Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific's performance to date and includes billed and unbilled amounts. As of December 31, 20182021 and December 31, 2017, accounts2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $57$78 million and $62$59 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Unamortized Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.
New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB ASC Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. Sierra Pacific adopted this guidance January 1, 2018 prospectively for the capitalization of the service cost component in the Balance Sheets and retrospectively for the presentation of the service cost component and the other components of net benefit cost in the Statements of Operations applying the practical expedient to use the amounts previously disclosed in the Notes to Financial Statements as the estimation basis for applying the retrospective presentation requirement. As a result, amounts other than the service cost for pension and other postretirement benefit plans for the years ended December 31, 2017 and 2016 of $1 million and $(1) million, respectively, have been reclassified to Other, net in the Statements of Operations.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Sierra Pacific adopted this guidance effective January 1, 2018 which did not have a material impact on its Financial Statements.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. Sierra Pacific adopted this guidance retrospectively effective January 1, 2018 which did not have a material impact on its Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases," ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption and ASU No. 2018-20 that provides targeted improvements to lessor accounting, such as the handling of sales and other similar taxes. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. Sierra Pacific adopted this guidance effective January 1, 2019, for all contracts currently in effect. Sierra Pacific is finalizing its implementation efforts relative to the new guidance and currently expects to recognize operating lease right of use assets and lease liabilities of approximately $20 million based on the contracts currently in-effect. Sierra Pacific currently does not believe the adoption of the new guidance will have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize Customer Revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. Sierra Pacific adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,163 | | | $ | 1,130 | |
Electric transmission | 50 - 100 years | | 940 | | | 908 | |
Electric distribution | 20 - 100 years | | 1,846 | | | 1,754 | |
Electric general and intangible plant | 5 - 70 years | | 204 | | | 189 | |
Natural gas distribution | 35 - 70 years | | 438 | | | 429 | |
Natural gas general and intangible plant | 5 - 70 years | | 14 | | | 15 | |
Common general | 5 - 70 years | | 370 | | | 355 | |
Utility plant | | | 4,975 | | | 4,780 | |
Accumulated depreciation and amortization | | | (1,854) | | | (1,755) | |
Utility plant, net | | | 3,121 | | | 3,025 | |
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | — | | | 2 | |
Plant, net | | | 3,121 | | | 3,027 | |
Construction work-in-progress | | | 219 | | | 137 | |
Property, plant and equipment, net | | | $ | 3,340 | | | $ | 3,164 | |
|
| | | | | | | | | |
| Depreciable Life | | 2018 | | 2017 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,144 |
| | $ | 1,144 |
|
Electric distribution | 20 - 100 years | | 1,568 |
| | 1,459 |
|
Electric transmission | 50 - 100 years | | 835 |
| | 786 |
|
Electric general and intangible plant | 5 - 70 years | | 197 |
| | 181 |
|
Natural gas distribution | 35 - 70 years | | 403 |
| | 390 |
|
Natural gas general and intangible plant | 5 - 70 years | | 14 |
| | 14 |
|
Common general | 5 - 70 years | | 321 |
| | 294 |
|
Utility plant | | | 4,482 |
| | 4,268 |
|
Accumulated depreciation and amortization | | | (1,593 | ) | | (1,513 | ) |
Utility plant, net | | | 2,889 |
| | 2,755 |
|
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | 5 |
| | 5 |
|
Plant, net | | | 2,894 |
| | 2,760 |
|
Construction work-in-progress | | | 90 |
| | 132 |
|
Property, plant and equipment, net | | | $ | 2,984 |
| | $ | 2,892 |
|
All of Sierra Pacific's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Sierra Pacific's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2018, 20172021, 2020 and 20162019 was 3.1%, 3.0%3.2% and 3.0%3.1%, respectively. Sierra Pacific is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2016.
Construction work-in-progress is primarily related to the construction of regulated assets.
In January 2017, Sierra Pacific revised its electric and gas depreciation rates based on the results of a new depreciation study performed in 2016, the most significant impact of which was shorter estimated useful lives at the Valmy Generating Station. The effect of this change increased depreciation and amortization expense by $9 million annually based on depreciable plant balances at the time of the study. However, the PUCN ordered the change relating to the Valmy Generating Station of $7 million annually be deferred for future recovery through a regulatory asset.
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements, Sierra Pacific, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Sierra Pacific accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Sierra Pacific's share of the expenses of these facilities.
The amounts shown in the table below represent Sierra Pacific's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 20182021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Sierra | | | | | | Construction |
| Pacific's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Valmy Generating Station | 50 | % | | $ | 394 | | | $ | 309 | | | $ | 1 | |
ON Line Transmission Line | 6 | | | 40 | | | 8 | | | — | |
Valmy Transmission | 50 | | | 4 | | | 2 | | | — | |
Total | | | $ | 438 | | | $ | 319 | | | $ | 1 | |
(5) Leases
The following table summarizes Sierra Pacific's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Right-of-use assets: | | | |
Operating leases | $ | 15 | | | $ | 16 | |
Finance leases | 111 | | | 126 | |
Total right-of-use assets | $ | 126 | | | $ | 142 | |
| | | |
Lease liabilities: | | | |
Operating leases | $ | 15 | | | $ | 16 | |
Finance leases | 115 | | | 130 | |
Total lease liabilities | $ | 130 | | | $ | 146 | |
|
| | | | | | | | | | | | | | |
| Sierra | | | | | | Construction |
| Pacific's | | Utility | | Accumulated | | Work-in- |
| Share | | Plant | | Depreciation | | Progress |
| | | | | | | |
Valmy Generating Station | 50 | % | | $ | 389 |
| | $ | 252 |
| | $ | 1 |
|
ON Line Transmission Line | 1 |
| | 8 |
| | 1 |
| | — |
|
Valmy Transmission | 50 |
| | 4 |
| | 2 |
| | — |
|
Total | | | $ | 401 |
| | $ | 255 |
| | $ | 1 |
|
The following table summarizes Sierra Pacific's lease costs for the years ended December 31 (in millions): | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Variable | $ | 86 | | | $ | 78 | | | $ | 69 | |
Operating | 1 | | | 2 | | | 1 | |
Finance: | | | | | |
Amortization | 5 | | | 4 | | | 2 | |
Interest | 9 | | | 9 | | | 2 | |
| | | | | |
Total lease costs | $ | 101 | | | $ | 93 | | | $ | 74 | |
| | | | | |
Weighted-average remaining lease term (years): | | | | | |
Operating leases | 27.4 | | 27.2 | | 26.3 |
Finance leases | 28.4 | | 27.8 | | 20.9 |
| | | | | |
Weighted-average discount rate: | | | | | |
Operating leases | 5.0 | % | | 5.0 | % | | 5.0 | % |
Finance leases | 8.2 | % | | 8.1 | % | | 7.1 | % |
(5)The following table summarizes Sierra Pacific's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
Operating cash flows from operating leases | $ | (1) | | | $ | (2) | | | $ | (3) | |
Operating cash flows from finance leases | (9) | | | (6) | | | (3) | |
Financing cash flows from finance leases | (7) | | | (5) | | | (3) | |
Right-of-use assets obtained in exchange for lease liabilities: | | | | | |
| | | | | |
Finance leases | $ | 1 | | | $ | 89 | | | $ | 5 | |
Sierra Pacific has the following remaining lease commitments as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Operating | | Finance | | Total |
2022 | $ | 1 | | | $ | 16 | | | $ | 17 | |
2023 | 1 | | | 16 | | | 17 | |
2024 | 1 | | | 15 | | | 16 | |
2025 | 1 | | | 15 | | | 16 | |
2026 | 1 | | | 15 | | | 16 | |
Thereafter | 24 | | | 149 | | | 173 | |
Total undiscounted lease payments | 29 | | | 226 | | | 255 | |
Less - amounts representing interest | (14) | | | (111) | | | (125) | |
Lease liabilities | $ | 15 | | | $ | 115 | | | $ | 130 | |
Operating and Finance Lease Obligations
Sierra Pacific's operating and finance lease obligations consist mainly of ON Line and Truckee-Carson Irrigation District ("TCID"). ON Line was placed in-service on December 31, 2013. Sierra Pacific and Nevada Power, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the necessary procedures to change the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved ownership percentage change from Nevada Power to Sierra Pacific. The term of the lease is 41 years with the agreement ending December 31, 2054. In 1999, Sierra Pacific entered into a 50-year agreement with TCID to lease electric distribution facilities. Total finance lease obligations of $110 million and $122 million were included on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively, for these leases. See Note 2 for further discussion of Sierra Pacific's remaining lease obligations.
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future rates. Sierra Pacific's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred energy costs | 1 year | | $ | 107 | | | $ | 22 | |
Merger costs from 1999 merger | 25 years | | 66 | | | 68 | |
Natural disaster protection plan | 1 year | | 62 | | | 45 | |
Employee benefit plans(1) | 8 years | | 46 | | | 81 | |
Unrealized loss on regulated derivative contracts | 1 year | | 35 | | | 2 | |
Deferred operating costs | 8 years | | 31 | | | 27 | |
Abandoned projects | 5 years | | 19 | | | 22 | |
| | | | | |
| | | | | |
Other | Various | | 74 | | | 67 | |
Total regulatory assets | | | $ | 440 | | | $ | 334 | |
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 177 | | | $ | 67 | |
Noncurrent assets | | | 263 | | | 267 | |
Total regulatory assets | | | $ | 440 | | | $ | 334 | |
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Employee benefit plans(1) | 8 years | | $ | 132 |
| | $ | 110 |
|
Merger costs from 1999 merger | 28 years | | 74 |
| | 77 |
|
Abandoned projects | 7 years | | 29 |
| | 34 |
|
Renewable energy programs | 1 year | | 4 |
| | 23 |
|
Losses on reacquired debt | 16 years | | 19 |
| | 21 |
|
Other | Various | | 63 |
| | 67 |
|
Total regulatory assets | | | $ | 321 |
| | $ | 332 |
|
| | | | | |
Reflected as: | | | | | |
Current assets | | | $ | 7 |
| | $ | 32 |
|
Other assets | | | 314 |
| | 300 |
|
Total regulatory assets | | | $ | 321 |
| | $ | 332 |
|
(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
| |
(1) | Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized. |
Sierra Pacific had regulatory assets not earning a return on investment of $190$158 million and $188$149 million as of December 31, 20182021 and 2017,2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, a portion of the employee benefit plans, losses on reacquired debt, asset retirement obligationsAROs and legacy meters.
Regulatory Liabilities
Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Sierra Pacific's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2021 | | 2020 |
| | | | | |
Deferred income taxes(1) | Various | | $ | 234 | | | $ | 249 | |
Cost of removal(2) | 36 years | | 201 | | | 197 | |
| | | | | |
| | | | | |
Other | Various | | 28 | | | 51 | |
Total regulatory liabilities | | | $ | 463 | | | $ | 497 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 19 | | | $ | 34 | |
Noncurrent liabilities | | | 444 | | | 463 | |
Total regulatory liabilities | | | $ | 463 | | | $ | 497 | |
|
| | | | | | | | | |
| Weighted | | | | |
| Average | | | | |
| Remaining Life | | 2018 | | 2017 |
| | | | | |
Deferred income taxes(1) | 28 years | | $ | 270 |
| | $ | 264 |
|
Cost of removal(2) | 40 years | | 210 |
| | 211 |
|
Deferred energy costs | 1 year | | — |
| | 8 |
|
Other | Various | | 29 |
| | 17 |
|
Total regulatory liabilities | | | $ | 509 |
| | $ | 500 |
|
| | | | | |
Reflected as: | | �� | | | |
Current liabilities | | | $ | 18 |
| | $ | 19 |
|
Other long-term liabilities | | | 491 |
| | 481 |
|
Total regulatory liabilities | | | $ | 509 |
| | $ | 500 |
|
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
| |
(1) | Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. Amount includes regulatory liabilities with an indeterminate life of $21 million and $- million as of December 31, 2018 and 2017, respectively. See Note 9 for further discussion of 2017 Tax Reform impacts. |
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
| |
(2) | Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. |
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Regulatory Rate ReviewNatural Disaster Protection Plan ("NDPP")
In March 2021, Sierra Pacific made filingsfiled an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Sierra Pacific filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the PUCN proposinglone dissenting party retaining the right to argue a taxsingle issue in future proceedings with the primary issue being a single statewide rate reduction rider foras a cost recovery mechanism. In July 2021, a hearing was held on the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. The filings supported an annual rate reductioncost recovery of $25 million.2020 expenditures. In March 2018,September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate reduction proposed by Sierra Pacific. The new ratesstructure. Certain vegetation management expenditures were effective April 1, 2018. Theto be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reformapproved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a hearing was held in July 2018.service territory specific rate component for capital costs. In September 2018,2021, Sierra Pacific and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order directing Sierra Pacific to record the amortization of any excess protected accumulated deferred income tax arisingreaffirming its order from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, Sierra Pacific filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Sierra Pacific filed a petition for judicial review.2021.
In March 2018, the FERC issued a Show Cause Order related to 2017 Tax Reform. In May 2018, in response to the Show Cause Order, Sierra Pacific proposed a reduction to transmission and certain ancillary service rates under the NV Energy OATT for the lower annual income tax expense anticipated from 2017 Tax Reform. In November 2018, FERC issued an order accepting the proposed rate reduction effective March 21, 2018 as filed and refunds to customers were made in December 2018 totaling $1 million for Sierra Pacific. In addition, FERC issued a notice of proposed rulemaking on public utility transmission rate changes to address accumulated deferred income taxes.
Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")
EEPR was established to allow Sierra Pacific to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Sierra Pacific and approved by the PUCN in integrated resource plan proceedings. To the extentPacific. When Sierra Pacific's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, Sierra Pacificit is requiredobligated to refund to customers EEIRenergy efficiency implementation revenue previously collected for that year. In March 2018,2021, Sierra Pacific filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2017,2020, including carrying charges. In September 2018,August 2021, the PUCN issued an order accepting a stipulation requiring Sierra Pacific to refund the 2020 revenue and reset the rates as filed effective October 1, 2018. The2021.The EEIR liability for Sierra Pacific is $2$1 million and $1$2 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 20182021 and 2017,2020, respectively.
Chapter 704B Applications
(7)Short-term Debt and Credit Facilities
Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one megawatt ("MW") or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution-only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs.
In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution-only service customer of Sierra Pacific. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee monthly for three years and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution-only service customer of Sierra Pacific. In January 2018, Caesars became a distribution-only service customer and started procuring energy from another energy supplier for its eligible meters in the Sierra Pacific service territory. Following the PUCN's order from March 2017, Caesars' will pay Sierra Pacific impact fees of $4 million in 36 equal monthly payments.
In May 2017, Peppermill Resort Spa Casino ("Peppermill"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution-only service customer of Sierra Pacific. In August 2017, the PUCN approved a stipulation allowing Peppermill to purchase energy from alternative providers subject to conditions, including paying an impact fee. In September 2017, Peppermill provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers. In April 2018, Peppermill paid a one-time impact fee of $3 million and became a distribution-only service customer and started procuring energy from another energy supplier.
(6)Credit Facility
The following table summarizes Sierra Pacific's availability under its credit facilities as of December 31 (in millions):
| | | | | | | | | | | | | | |
| | 2021 | | 2020 |
Credit facilities | | $ | 250 | | | $ | 250 | |
Short-term debt | | (159) | | | (45) | |
| | | | |
Net credit facilities | | $ | 91 | | | $ | 205 | |
|
| | | | | | | | |
| | 2018 | | 2017 |
Credit facilities | | $ | 250 |
| | $ | 250 |
|
Less - Water Facilities Refunding Revenue Bond support | | (80 | ) | | (80 | ) |
Net credit facilities | | $ | 170 |
| | $ | 170 |
|
Sierra Pacific has a $250 million secured credit facility expiring in June 20212024 with a one-yearan unlimited number of maturity extension optionoptions, subject to lender consent. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long‑term debt securities. As of December 31, 20182021 and 2017,2020, Sierra Pacific had no borrowings of $159 million and $45 million, respectively, outstanding under the credit facility. As of December 31, 2021 and 2020, the weighted average interest rate on borrowings outstanding was 0.86% and 0.90%, respectively. Amounts due under Sierra Pacific's credit facility are collateralized by Sierra Pacific's general and refunding mortgage bonds. The credit facility requires Sierra Pacific's ratio of debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.
(7) Long-Term
(8) Long-term Debt and Financial and Capital Lease Obligations
Sierra Pacific's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
General and refunding mortgage securities: | | | | | |
3.375% Series T, due 2023 | $ | 250 | | | $ | 249 | | | $ | 249 | |
2.600% Series U, due 2026 | 400 | | | 397 | | | 396 | |
6.750% Series P, due 2037 | 252 | | | 253 | | | 255 | |
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
| | | | | |
1.850% Pollution Control Series 2016B, due 2029 (1) | 30 | | | 30 | | | 29 | |
| | | | | |
3.000% Gas and Water Series 2016B, due 2036 (2) | 60 | | | 60 | | | 61 | |
0.625% Water Facilities Series 2016C, due 2036 (1) | 30 | | | 30 | | | 30 | |
2.050% Water Facilities Series 2016D, due 2036 (1) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016E, due 2036 (1) | 25 | | | 25 | | | 25 | |
2.050% Water Facilities Series 2016F, due 2036 (1) | 75 | | | 75 | | | 74 | |
1.850% Water Facilities Series 2016G, due 2036 (1) | 20 | | | 20 | | | 20 | |
Total long-term debt | $ | 1,167 | | | $ | 1,164 | | | $ | 1,164 | |
| | | | | |
Reflected as - | | | | | |
| | | | | |
Long-term debt | | | $ | 1,164 | | | $ | 1,164 | |
| | | | | |
|
| | | | | | | | | | | |
| Par Value | | 2018 | | 2017 |
General and refunding mortgage securities: | | | | | |
3.375% Series T, due 2023 | $ | 250 |
| | $ | 249 |
| | $ | 248 |
|
2.600% Series U, due 2026 | 400 |
| | 396 |
| | 396 |
|
6.750% Series P, due 2037 | 252 |
| | 255 |
| | 255 |
|
Tax-exempt refunding revenue bond obligations: | | | | | |
Fixed-rate series: | | | | | |
1.250% Pollution Control Series 2016A, due 2029(1) | 20 |
| | 20 |
| | 20 |
|
1.500% Gas Facilities Series 2016A, due 2031(1) | 59 |
| | 58 |
| | 58 |
|
3.000% Gas and Water Series 2016B, due 2036(2) | 60 |
| | 62 |
| | 63 |
|
Variable-rate series (2018 - 1.750% to 1.820%, 2017 - 1.690% to 1.840%): | | | | | |
Water Facilities Series 2016C, due 2036 | 30 |
| | 30 |
| | 30 |
|
Water Facilities Series 2016D, due 2036 | 25 |
| | 25 |
| | 25 |
|
Water Facilities Series 2016E, due 2036 | 25 |
| | 25 |
| | 25 |
|
Capital and financial lease obligations - 2.700% to 10.297%, due through 2054 | 38 |
| | 38 |
| | 34 |
|
Total long-term debt and financial and capital leases | $ | 1,159 |
| | $ | 1,158 |
| | $ | 1,154 |
|
| | | | | |
Reflected as: | | | | | |
Current portion of long-term debt and financial and capital lease obligations | | | $ | 3 |
| | $ | 2 |
|
Long-term debt and financial and capital lease obligations | | | 1,155 |
| | 1,152 |
|
Total long-term debt and financial and capital leases | | | $ | 1,158 |
| | $ | 1,154 |
|
(1)Subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.
| |
(1) | Subject to mandatory purchase by Sierra Pacific in June 2019 at which date the interest rate may be adjusted from time to time. |
| |
(2) | Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted from time to time. |
(2)Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted.
Annual Payment on Long-Term Debt and Financial and Capital Leases
The annual repayments of long-term debt and capital and financial leases for the years beginning January 1, 20192022 and thereafter, are as follows (in millions):
| | | | | |
| |
| |
| |
| |
2023 | $ | 250 | |
| |
| |
2026 | 400 | |
2027 and thereafter | 517 | |
Total | 1,167 | |
Unamortized premium, discount and debt issuance cost | (3) | |
| |
| |
Total | $ | 1,164 | |
|
| | | | | | | | | | | | |
| | Long-term | | Capital and Financial | | |
| | Debt | | Lease Obligations | | Total |
| | | | | | |
2019 | | $ | — |
| | $ | 6 |
| | $ | 6 |
|
2020 | | — |
| | 4 |
| | 4 |
|
2021 | | — |
| | 5 |
| | 5 |
|
2022 | | — |
| | 4 |
| | 4 |
|
2023 | | 250 |
| | 4 |
| | 254 |
|
Thereafter | | 871 |
| | 47 |
| | 918 |
|
Total | | 1,121 |
| | 70 |
| | 1,191 |
|
Unamortized premium, discount and debt issuance cost | | (1 | ) | | — |
| | (1 | ) |
Amounts representing interest | | — |
| | (32 | ) | | (32 | ) |
Total | | $ | 1,120 |
| | $ | 38 |
| | $ | 1,158 |
|
The issuance of General and Refunding Mortgage Securities by Sierra Pacific is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2018,2021, approximately $4.1$4.5 billion (based on original cost) of Sierra Pacific's property was subject to the liens of the mortgages.
Financial and Capital Lease Obligations
(9) Income Taxes
Sierra Pacific has master leasing agreements of which various pieces of equipment qualify as capital leases. The remaining equipment is treated as operating leases. Lease terms under the master lease agreement are typically five to seven years. Capital assets of $8 million and $3 million were included in property, plant and equipment, net as of December 31, 2018 and 2017.
ON Line was placed in-service on December 31, 2013. The Nevada Utilities entered into a long-term transmission use agreement, in which the Nevada Utilities have 25% interest and Great Basin Transmission South, LLC has 75% interest. Refer to Note 4 for additional information. The Nevada Utilities share of the long-term transmission use agreement and ownership interest is split at 5% for Sierra Pacific and 95% for Nevada Power. The term is for 41 years with the agreement ending December 31, 2054. Payments began on January 31, 2014. ON Line assets of $20 million and $21 million were included in property, plant and equipment, net as of December 31, 2018 and 2017.
In 2015, Sierra Pacific entered into a 20-year capital lease for the Fort Churchill Solar Array. Capital assets of $9 million were included in property, plant and equipment, net as of December 31, 2018 and 2017.
| |
(8) | Fair Value Measurements |
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2018: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
|
Money market mutual funds(1) | 45 |
| | — |
| | — |
| | 45 |
|
| $ | 45 |
| | $ | — |
| | $ | 2 |
| | $ | 47 |
|
| | | | | | | |
As of December 31, 2017: | | | | | | | |
Assets - investment funds | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | |
| |
(1) | Amounts are included in cash and cash equivalents on the Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Sierra Pacific's long-term debt is carried at cost on the Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt as of December 31 (in millions):
|
| | | | | | | | | | | | | | | |
| 2018 | | 2017 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 1,120 |
| | $ | 1,167 |
| | $ | 1,120 |
| | $ | 1,221 |
|
Tax Cuts and Jobs Act
The 2017 Tax Reform impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, limitations on bonus depreciation for utility property and the elimination of the deduction for production activities. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, Sierra Pacific reduced deferred income tax liabilities $342 million. As it was probable the change in deferred taxes would be passed back to customers through regulatory mechanisms, Sierra Pacific increased net regulatory liabilities by $341 million.
In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. Sierra Pacific recorded the impacts of the 2017 Tax Reform in December 2017 and believed all the impacts to be complete with the exception of the interpretation of the bonus depreciation rules. Sierra Pacific determined the amounts recorded and the interpretation relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. Sierra Pacific believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, Sierra Pacific finalized its provisional amounts and recorded a current tax benefit and deferred tax expense of $4 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform and Sierra Pacific's regulatory nature, Sierra Pacific reduced the associated deferred income tax liabilities $2 million and increased regulatory liabilities by the same amount.
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Current – Federal | $ | 5 | | | $ | 3 | | | $ | 19 | |
| | | | | |
Deferred – Federal | 13 | | | 12 | | | 10 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Investment tax credits | — | | | — | | | (1) | |
Total income tax expense | $ | 18 | | | $ | 15 | | | $ | 28 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Current – Federal | $ | 23 |
| | $ | — |
| | $ | — |
|
Deferred – Federal | 7 |
| | 56 |
| | 50 |
|
Uncertain tax positions | 1 |
| | — |
| | — |
|
Investment tax credits | (1 | ) | | (1 | ) | | (1 | ) |
Total income tax expense | $ | 30 |
| | $ | 55 |
| | $ | 49 |
|
A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (8) | | | (9) | | | — | |
| | | | | |
| | | | | |
| | | | | |
Effective income tax rate | 13 | % | | 12 | % | | 21 | % |
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
Non-deductible expenses | 4 |
| | — |
| | — |
|
Effects of ratemaking | — |
| | — |
| | 1 |
|
Effect of tax rate change | — |
| | (1 | ) | | — |
|
Other | — |
| | — |
| | 1 |
|
Effective income tax rate | 25 | % | | 34 | % | | 37 | % |
The net deferred income tax liability consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 64 | | | $ | 67 | |
| | | |
| | | |
Operating and finance leases | 27 | | | 30 | |
Customer advances | 14 | | | 10 | |
Unamortized contract value | 8 | | | 2 | |
Other | 6 | | | 8 | |
Total deferred income tax assets | 119 | | | 117 | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (379) | | | (380) | |
Regulatory assets | (94) | | | (74) | |
Operating and finance leases | (27) | | | (30) | |
Other | (21) | | | (7) | |
Total deferred income tax liabilities | (521) | | | (491) | |
Net deferred income tax liability | $ | (402) | | | $ | (374) | |
| | | |
| | | |
| | | |
| | | |
| | | |
|
| | | | | | | |
| 2018 | | 2017 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 70 |
| | $ | 67 |
|
Federal net operating loss and credit carryforwards | — |
| | 10 |
|
Employee benefit plans | 10 |
| | 10 |
|
Capital and financial leases | 8 |
| | 7 |
|
Customer Advances | 8 |
| | 7 |
|
Other | 6 |
| | 6 |
|
Total deferred income tax assets | 102 |
| | 107 |
|
| | | |
Deferred income tax liabilities: | | | |
Property related items | (346 | ) | | (349 | ) |
Regulatory assets | (73 | ) | | (74 | ) |
Capital and financial leases | (8 | ) | | (7 | ) |
Other | (6 | ) | | (7 | ) |
Total deferred income tax liabilities | (433 | ) | | (437 | ) |
Net deferred income tax liability | $ | (331 | ) | | $ | (330 | ) |
The United States Internal Revenue Service has closed its examination of NV Energy’sEnergy's consolidated income tax returns through December 31, 2008, and effectively settled its examination of Sierra Pacific's income tax return for the short year ended December 31, 2013, and the statute of limitations has expired for NV Energy’sEnergy's consolidated income tax returns through the short year ended December 19, 2013. The closure or effective settlement of examinations, or the expiration of the statute of limitations expiring may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.
(10) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $6 million, $1 million and $27 milliondid not make any contributions to the Qualified Pension Plan for the yearyears ended December 31, 2018, 20172021, 2020 and 2016, respectively. For the Other Postretirement Plans,2019. Sierra Pacific contributed $6 million, $4 million and $1 million for the year ended December 31, 2018, 2017 and 2016, respectively. Sierra Pacific contributed $1 million, $1 million and $- million to the Non-Qualified Pension Plans for the years ended December 31, 2021, 2020 and 2019. Sierra Pacific contributed $1 million to the Other Post Retirement Plan for the year ended December 31, 2018, 20172021. Sierra Pacific did not make any contributions to the Other Post Retirement Plans for the years ended December 31, 2020 and 2016, respectively.2019. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts payable toreceivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31(in31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Qualified Pension Plan - | | | |
Other non-current assets | $ | 62 | | | $ | 26 | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (7) | | | (8) | |
| | | |
Other Postretirement Plans - | | | |
Other long-term liabilities | (10) | | | (13) | |
|
| | | | | | | |
| 2018 | | 2017 |
Qualified Pension Plan - | | | |
Other long-term liabilities | $ | (19 | ) | | $ | (2 | ) |
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | (1 | ) | | (1 | ) |
Other long-term liabilities | (7 | ) | | (8 | ) |
| | | |
Other Postretirement Plans - | | | |
Other long-term liabilities | (13 | ) | | (20 | ) |
(11) Asset Retirement Obligations
Sierra Pacific estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Sierra Pacific does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $210$201 million and $211$197 million as of December 31, 20182021 and 2017,2020, respectively.
The following table presents Sierra Pacific's ARO liabilities by asset type as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Asbestos | $ | 5 | | | $ | 5 | |
Evaporative ponds and dry ash landfills | 3 | | | 3 | |
Other | 3 | | | 3 | |
Total asset retirement obligations | $ | 11 | | | $ | 11 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Asbestos | $ | 5 |
| | $ | 5 |
|
Evaporative ponds and dry ash landfills | 2 |
| | 2 |
|
Other | 3 |
| | 3 |
|
Total asset retirement obligations | $ | 10 |
| | $ | 10 |
|
The following table reconciles the beginning and ending balances of Sierra Pacific's ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 11 | | | $ | 10 | |
| | | |
| | | |
| | | |
Accretion | — | | | 1 | |
Ending balance | $ | 11 | | | $ | 11 | |
| | | |
Reflected as - | | | |
| | | |
| | | |
Other long-term liabilities | $ | 11 | | | $ | 11 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 10 |
| | $ | 10 |
|
Retirements | — |
| | — |
|
Ending balance | $ | 10 |
| | $ | 10 |
|
| | | |
Reflected as: | | | |
Other current liabilities | $ | — |
| | $ | — |
|
Other long-term liabilities | 10 |
| | 10 |
|
| $ | 10 |
| | $ | 10 |
|
Certain of Sierra Pacific's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Sierra Pacific is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Sierra Pacific's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
| |
(12) | Commitments and Contingencies |
(12)Risk Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 2 | | | | | $ | — | | | $ | — | | | $ | 2 | |
Commodity liabilities | — | | | | | (16) | | | (19) | | | (35) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 2 | | | | | $ | (16) | | | $ | (19) | | | $ | (33) | |
| | | | | | | | | |
As of December 31, 2020: | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 9 | | | | | $ | — | | | $ | — | | | $ | 9 | |
Commodity liabilities | — | | | | | — | | | (2) | | | (2) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 9 | | | | | $ | — | | | $ | (2) | | | $ | 7 | |
(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2021 a regulatory asset of $33 million was recorded related to the net derivative liability of $33 million. As of December 31, 2020 a regulatory liability of $7 million was recorded related to the net derivative asset of $7 million.
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | | | |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity purchases | Megawatt hours | | 1 | | | — | |
Natural gas purchases | Decatherms | | 53 | | | 54 | |
| | | | | |
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2021, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $— million as of December 31, 2021 and 2020, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | |
Money market mutual funds | 10 | | | — | | | — | | | 10 | |
Investment funds | 1 | | | — | | | — | | | 1 | |
| $ | 11 | | | $ | — | | | $ | 2 | | | $ | 13 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (35) | | | $ | (35) | |
| | | | | | | |
As of December 31, 2020: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | |
Money market mutual funds | 17 | | | — | | | — | | | 17 | |
| $ | 17 | | | $ | — | | | $ | 9 | | | $ | 26 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of December 31, 2021, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Sierra Pacific's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
Beginning balance | | $ | 7 | | | $ | (1) | | | $ | 2 | |
Changes in fair value recognized in regulatory assets or liabilities | | (25) | | | (2) | | | (5) | |
| | | | | | |
Settlements | | (15) | | | 10 | | | 2 | |
Ending balance | | $ | (33) | | | $ | 7 | | | $ | (1) | |
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 1,164 | | | $ | 1,316 | | | $ | 1,164 | | | $ | 1,358 | |
(14) Commitments and Contingencies
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Commitments
Sierra Pacific has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 20182021 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2027 and | | |
| 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 338 | | | $ | 227 | | | $ | 149 | | | $ | 120 | | | $ | 105 | | | $ | 1,072 | | | $ | 2,011 | |
Fuel and capacity contract commitments (not commercially operable) | 25 | | | 27 | | | 27 | | | 26 | | | 26 | | | 459 | | | 590 | |
Construction commitments | 35 | | | 497 | | | 737 | | | 76 | | | — | | | — | | | 1,345 | |
| | | | | | | | | | | | | |
Easements | 2 | | | 2 | | | 2 | | | 2 | | | 2 | | | 28 | | | 38 | |
Maintenance, service and other contracts | 7 | | | 6 | | | 6 | | | 5 | | | 1 | | | — | | | 25 | |
Total commitments | $ | 407 | | | $ | 759 | | | $ | 921 | | | $ | 229 | | | $ | 134 | | | $ | 1,559 | | | $ | 4,009 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2024 and | | |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
Contract type: | | | | | | | | | | | | | |
Fuel, capacity and transmission contract commitments | $ | 204 |
| | $ | 154 |
| | $ | 117 |
| | $ | 81 |
| | $ | 61 |
| | $ | 502 |
| | $ | 1,119 |
|
Fuel and capacity contract commitments (not commercially operable) | 8 |
| | 16 |
| | 28 |
| | 58 |
| | 58 |
| | 1,394 |
| | 1,562 |
|
Operating leases and easements | 4 |
| | 4 |
| | 4 |
| | 3 |
| | 2 |
| | 56 |
| | 73 |
|
Maintenance, service and other contracts | 8 |
| | 7 |
| | 6 |
| | 6 |
| | 2 |
| | 1 |
| | 30 |
|
Total commitments | $ | 224 |
| | $ | 181 |
| | $ | 155 |
| | $ | 148 |
| | $ | 123 |
| | $ | 1,953 |
| | $ | 2,784 |
|
Fuel and Capacity Contract Commitments
Purchased Power
Sierra Pacific has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 20192022 to 2045.2046. Purchased power includes estimated payments for contracts which meet the definition of a lease.lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Sierra Pacific's operating and maintenance expense for purchase power contracts which met the lease criteria for 2018, 2017 and 2016 were $72 million, $74 million and $69 million, respectively, and are recorded as cost of fuel, energy and capacity on the Statements of Operations.commitments.
Coal and Natural Gas
Sierra Pacific has a long-term contract for the transport of coal that expires in 2019.2024. Additionally, gas transportation contracts expire from 20192023 to 2046 and the gas supply contracts expire from 20192022 to 2020.2023.
Operating LeasesFuel and EasementsCapacity Contract Commitments - Not Commercially Operable
Sierra Pacific has non-cancelable operating leases primarilyseveral contracts for office equipment, office space, certain operatinglong-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Construction Commitments
Sierra Pacific's construction commitments included in the table above relate to firm commitments and include costs associated with two solar photovoltaic facility projects. The first project is a 250-MW solar photovoltaic facility with an additional 200 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 350-MW solar photovoltaic facility with an additional 280 MWs of co-located battery storage that will be developed in Humboldt County, Nevada. Commercial operation is expected by the end of 2024. Both facilities vehicleswill be jointly owned and land. These leases generally requireoperated by Nevada Power and Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Pacific.
Easements
Sierra Pacific also has non-cancelable easements for land. Operating and maintenance expense on non-cancelable operating leases and easements totaled $4 million, $4 million and $6$2 million for the year-endedyears-ended December 31, 2018, 20172021, 2020 and 2016, respectively.2019.
Maintenance, Service and Other Contracts
Sierra Pacific has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 20192024 to 2039.2026.
400
| |
(13) | Revenues from Contracts with Customers
|
(15) Revenues from Contracts with Customers
The following table summarizes Sierra Pacific's revenueCustomer Revenue by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 16,18, for the yearyears ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | | | |
Residential | $ | 307 | | | $ | 76 | | | $ | 383 | | | $ | 273 | | | $ | 76 | | | $ | 349 | | | $ | 268 | | | $ | 76 | | | $ | 344 | |
Commercial | 267 | | | 29 | | | 296 | | | 233 | | | 29 | | | 262 | | | 245 | | | 30 | | | 275 | |
Industrial | 202 | | | 10 | | | 212 | | | 170 | | | 9 | | | 179 | | | 186 | | | 10 | | | 196 | |
Other | 5 | | | — | | | 5 | | | 5 | | | — | | | 5 | | | 6 | | | 1 | | | 7 | |
Total fully bundled | 781 | | | 115 | | | 896 | | | 681 | | | 114 | | | 795 | | | 705 | | | 117 | | | 822 | |
Distribution only service | 3 | | | — | | | 3 | | | 4 | | | — | | | 4 | | | 4 | | | — | | | 4 | |
Total retail | 784 | | | 115 | | | 899 | | | 685 | | | 114 | | | 799 | | | 709 | | | 117 | | | 826 | |
Wholesale, transmission and other | 62 | | | — | | | 62 | | | 50 | | | — | | | 50 | | | 57 | | | — | | | 57 | |
Total Customer Revenue | 846 | | | 115 | | | 961 | | | 735 | | | 114 | | | 849 | | | 766 | | | 117 | | | 883 | |
Other revenue | 2 | | | 2 | | | 4 | | | 3 | | | 2 | | | 5 | | | 4 | | | 2 | | | 6 | |
Total revenue | $ | 848 | | | $ | 117 | | | $ | 965 | | | $ | 738 | | | $ | 116 | | | $ | 854 | | | $ | 770 | | | $ | 119 | | | $ | 889 | |
|
| | | | | | | | | | | |
| 2018 |
| Electric | | Gas | | Total |
Customer Revenue: | | | | | |
Retail: | | | | | |
Residential | $ | 267 |
| | $ | 67 |
| | $ | 334 |
|
Commercial | 246 |
| | 25 |
| | 271 |
|
Industrial | 177 |
| | 8 |
| | 185 |
|
Other | 6 |
| | 1 |
| | 7 |
|
Total fully bundled | 696 |
| | 101 |
| | 797 |
|
Distribution only service | 4 |
| | — |
| | 4 |
|
Total retail | 700 |
| | 101 |
| | 801 |
|
Wholesale, transmission and other | 48 |
| | — |
| | 48 |
|
Total Customer Revenue | 748 |
| | 101 |
| | 849 |
|
Other revenue | 4 |
| | 2 |
| | 6 |
|
Total revenue | $ | 752 |
| | $ | 103 |
| | $ | 855 |
|
Contract Assets and Liabilities
In the event one of the parties to a contract has performed before the other, Sierra Pacific would recognize a contract asset or contract liability depending on the relationship between Sierra Pacific's performance and the customer's payment. As of December 31, 2018 and December 31, 2017, there were no contract assets or contract liabilities recorded on the Balance Sheets.
(14) Related Party Transactions
Sierra Pacific has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Sierra Pacific under this agreement totaled $1 million for the years ended December 31, 2018, 2017 and 2016.
Sierra Pacific provided electricity to Nevada Power of $28 million, $21 million and $17 million for the years ended December 31, 2018, 2017 and 2016, respectively. Receivables associated with these transactions were $1 million and $- million as of December 31, 2018 and 2017, respectively. Sierra Pacific purchased electricity from Nevada Power of $91 million, $104 million and $78 million for the years ended December 31, 2018, 2017 and 2016, respectively. Payables associated with these transactions were $6 million and $10 million as of December 31, 2018 and 2017, respectively.
Sierra Pacific incurs intercompany administrative and shared facility costs with NV Energy and Nevada Power. These transactions are governed by an intercompany service agreement and are priced at cost. NV Energy provided services to Sierra Pacific of $4 million, $5 million and $5 million for the years ending December 31, 2018, 2017 and 2016, respectively. Sierra Pacific provided services to Nevada Power of $15 million, $17 million, and $14 million for the years ended December 31, 2018, 2017 and 2016, respectively. Nevada Power provided services to Sierra Pacific of $28 million, $27 million, and $24 million for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, Sierra Pacific's Balance Sheets included amounts due to NV Energy of $15 million and $17 million, respectively. There were no receivables due from NV Energy as of December 31, 2018 and 2017. As of December 31, 2018 and 2017, Sierra Pacific's Balance Sheets included payables due to Nevada Power of $5 million. There were no receivables due from Nevada Power as of December 31, 2018 and 2017.
Sierra Pacific is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. Federal income taxes payable to NV Energy were $3 million and $- million as of December 31, 2018 and 2017, respectively. Sierra Pacific made cash payments of $19 million for federal income taxes for the year ended December 31, 2018. No cash payments were made for federal income taxes for the years ended December 31, 2017 and 2016.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Sierra Pacific and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
(15)(16)Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 20182021 and December 31, 2017,2020, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN")PUCN for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 20182021 and December 31, 2017,2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| December 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 10 | | | $ | 19 | |
Restricted cash and cash equivalents included in other current assets | 6 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 16 | | | $ | 26 | |
|
| | | | | | | |
| As of |
| December 31, | | December 31, |
| 2018 | | 2017 |
Cash and cash equivalents | $ | 71 |
| | $ | 4 |
|
Restricted cash and cash equivalents included in other current assets | 5 |
| | 4 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 76 |
| | $ | 8 |
|
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 41 | | | $ | 42 | | | $ | 41 | |
Income taxes (refunded) paid | $ | (3) | | | $ | 2 | | | $ | 37 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 27 | | | $ | 17 | | | $ | 18 | |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Supplemental disclosure of cash flow information - | | | | | |
Interest paid, net of amounts capitalized | $ | 41 |
| | $ | 40 |
| | $ | 47 |
|
Income taxes paid | $ | 19 |
| | $ | — |
| | $ | — |
|
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 15 |
| | $ | 10 |
| | $ | 15 |
|
Capital and financial lease obligations incurred | $ | 6 |
| | $ | 1 |
| | $ | — |
|
(17) Related Party Transactions
(16)
Sierra Pacific has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Sierra Pacific under this agreement totaled $2 million, $1 million and $1 million for the years ended December 31, 2021, 2020 and 2019.
Sierra Pacific provided electricity to Nevada Power of $43 million, $34 million and $25 million for the years ended December 31, 2021, 2020 and 2019, respectively. Receivables associated with these transactions were $— million and $1 million as of December 31, 2021 and 2020, respectively. Sierra Pacific purchased electricity from Nevada Power of $179 million, $106 million and $84 million for the years ended December 31, 2021, 2020 and 2019, respectively. Payables associated with these transactions were $13 million as of December 31, 2021 and 2020.
Sierra Pacific incurs intercompany administrative and shared facility costs with NV Energy and Nevada Power. These transactions are governed by an intercompany service agreement and are priced at cost. NV Energy provided services to Sierra Pacific of $5 million, $5 million and $4 million for the years ending December 31, 2021, 2020 and 2019, respectively. Sierra Pacific provided services to Nevada Power of $15 million, $15 million, and $14 million for the years ended December 31, 2021, 2020 and 2019, respectively. Nevada Power provided services to Sierra Pacific of $25 million, $26 million, and $26 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, Sierra Pacific's Consolidated Balance Sheets included amounts due to NV Energy of $19 million and $17 million, respectively. There were no receivables due from NV Energy as of December 31, 2021 and 2020. As of December 31, 2021 and 2020, Sierra Pacific's Consolidated Balance Sheets included payables due to Nevada Power of $2 million. There were no receivables due from Nevada Power as of December 31, 2021 and 2020.
Sierra Pacific is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. As of December 31, 2021 and 2020 federal income taxes receivable from NV Energy were $— million and $7 million, respectively. Sierra Pacific received cash refunds of $3 million for federal income taxes for the year ended December 31, 2021 and made cash payments of $2 million and $37 million for federal income taxes for the years ended December 31, 2020 and 2019, respectively.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Sierra Pacific and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
In January 2022, Sierra Pacific received a capital contribution of $130 million from NV Energy, Inc.
(18)Segment Information
Sierra Pacific has identified two2 reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.
The following tables provide information on a reportable segment basis (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
Operating revenue: | | | | | | |
Regulated electric | | $ | 848 | | | $ | 738 | | | $ | 770 | |
Regulated natural gas | | 117 | | | 116 | | | 119 | |
Total operating revenue | | $ | 965 | | | $ | 854 | | | $ | 889 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Operating income: | | | | | | |
Regulated electric | | $ | 148 | | | $ | 147 | | | $ | 150 | |
Regulated natural gas | | 19 | | | 18 | | | 21 | |
Total operating income | | 167 | | | 165 | | | 171 | |
Interest expense | | (54) | | | (56) | | | (48) | |
Allowance for borrowed funds | | 2 | | | 2 | | | 1 | |
Allowance for equity funds | | 7 | | | 4 | | | 3 | |
Interest and dividend income | | 9 | | | 4 | | | 3 | |
Other, net | | 11 | | | 7 | | | 1 | |
Income before income tax expense | | $ | 142 | | | $ | 126 | | | $ | 131 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2021 | | 2020 | | 2019 |
Assets | | | | | | |
Regulated electric | | $ | 3,829 | | | $ | 3,540 | | | $ | 3,319 | |
Regulated natural gas | | 365 | | | 342 | | | 308 | |
Regulated common assets(1) | | 29 | | | 37 | | | 44 | |
Total assets | | $ | 4,223 | | | $ | 3,919 | | | $ | 3,671 | |
(1) Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
|
| | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 |
| 2017 |
| 2016 |
Operating revenue: | | | | | | |
Regulated electric | | $ | 752 |
| | $ | 713 |
| | $ | 702 |
|
Regulated gas | | 103 |
| | 99 |
| | 110 |
|
Total operating revenue | | $ | 855 |
| | $ | 812 |
| | $ | 812 |
|
| | | | | | |
Operating income: | | | | | | |
Regulated electric | | $ | 136 |
| | $ | 175 |
| | $ | 162 |
|
Regulated gas | | 16 |
| | 22 |
| | 19 |
|
Total operating income | | 152 |
| | 197 |
| | 181 |
|
Interest expense | | (44 | ) | | (43 | ) | | (54 | ) |
Allowance for borrowed funds | | 1 |
| | 2 |
| | 4 |
|
Allowance for equity funds | | 4 |
| | 3 |
| | (1 | ) |
Other, net | | 9 |
| | 5 |
| | 3 |
|
Income before income tax expense | | $ | 122 |
| | $ | 164 |
| | $ | 133 |
|
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
|
| | | | | | | | | | | | |
| | As of December 31, |
| | 2018 | | 2017 | | 2016 |
Assets | | | | | | |
Regulated electric | | $ | 3,177 |
| | $ | 3,103 |
| | $ | 3,119 |
|
Regulated gas | | 314 |
| | 300 |
| | 314 |
|
Regulated common assets(1) | | 78 |
| | 10 |
| | 60 |
|
Total assets | | $ | 3,569 |
| | $ | 3,413 |
| | $ | 3,493 |
|
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income attributable to Eastern Energy Gas for the year ended December 31, 2021 was $262 million, an increase of $153 million, or 140%, compared to 2020, primarily due to a 2020 charge of $463 million associated with the probable abandonment of a significant portion of a project previously intended for EGTS to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project") and a 2020 charge of $141 million for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction. These increases were partially offset by an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point of $226 million and the November 2020 disposition of Questar Pipeline Group of $75 million, both of which were a result of the GT&S Transaction, and income tax expense of $117 million in 2021 versus income tax benefit of $24 million in 2020, primarily due to higher pre-tax income.
Net income attributable to Eastern Energy Gas for the year ended December 31, 2020 was $109 million, a decrease of $612 million, or 85%, compared to 2019, primarily due to a charge associated with the probable abandonment of the Supply Header Project of $463 million, a charge for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction of $141 million, interest income from Cove Point's notes receivable from DEI of $82 million recognized in 2019, a charge for disallowance of capitalized AFUDC due to the resolution of EGTS' 2015 FERC audit of $43 million and an increase in net income attributable to noncontrolling interests due to DEI's 50% interest in Cove Point effective with the GT&S Transaction of $39 million. These decreases are partially offset by interest expense of $100 million recognized in 2019 from Cove Point's term loan borrowings and income tax benefit of $24 million in 2020 versus income tax expense of $101 million in 2019, primarily due to lower pre-tax income.
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Operating revenue decreased $220 million, or 11%, for 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $197 million and a decrease in services performed for Atlantic Coast Pipeline of $43 million, which is offset in operations and maintenance expense, partially offset by an increase in regulated gas revenues for operational and system balancing purposes primarily due to increased prices of $15 million.
Cost of gas decreased $12 million, or 50%, for 2021 compared to 2020, primarily due to a favorable change in natural gas prices of $55 million and the November 2020 disposition of Questar Pipeline Group of $3 million, partially offset by an increase in prices of natural gas sold of $49 million.
Operations and maintenance decreased $627 million, or 55%, for 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of the Supply Header Project of $463 million, a decrease in services performed for Atlantic Coast Pipeline of $45 million, the November 2020 disposition of Questar Pipeline Group of $43 million, a 2020 charge for disallowance of capitalized AFUDC due to the resolution of EGTS' 2015 FERC audit of $43 million, the 2020 write-off of certain items in connection with the GT&S Transaction of $17 million and a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC of $11 million.
Depreciation and amortization decreased $38 million, or 10%, for 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.
Property and other taxes increased $9 million, or 6%, for 2021 compared to 2020, primarily due to higher tax assessments.
Interest expense decreased $188 million, or 55%, for 2021 compared to 2020, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $16 million and lower interest expense of $17 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $5 million from the repayment of $500 million of long-term debt in the second quarter of 2021.
Allowance for borrowed funds decreased $4 million, or 67%, for 2021 compared to 2020, primarily due to the 2020 abandonment of the Supply Header Project.
Allowance for equity funds decreased $6 million, or 46%, for 2021 compared to 2020, primarily due to the 2020 abandonment of the Supply Header Project.
Interest and dividend income decreased $67 million for 2021 compared to 2020, primarily due to interest income from the East Ohio Gas Company of $33 million and DEI of $32 million recognized in 2020.
Other, net decreased $41 million, or 98%, for 2021 compared to 2020, primarily due to non-service cost credits recognized in 2020 related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.
Income tax expense (benefit) was an expense of $117 million for 2021 compared to a benefit of $24 million for 2020. The effective tax rate was 16% in 2021 and (12)% in 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project in 2020 and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.
Net income attributable to noncontrolling interests increased $226 million for 2021 compared to 2020, primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Operating revenue decreased $79 million, or 4%, for 2020 compared to 2019, primarily due to:
•$55 million decrease in services performed for Atlantic Coast Pipeline, which is offset in operations and maintenance expense;
•$45 million from the absence of Questar Pipeline Group operations from the date of the GT&S Transaction;
•$18 million from the absence of EGTS contract changes; and
•$14 million decrease in services provided to affiliates.
The decrease in operating revenue was offset by:
•$35 million increase in regulated gas sales primarily due to increased volumes; and
•$23 million from the absence of credits associated with the start-up phase of the Liquefaction Facility.
Cost of gas increased $15 million, or 167%, for 2020 compared to 2019, primarily due to an increase in volumes sold.
Operations and maintenance increased $394 million, or 53%, for 2020 compared to 2019, primarily due to a charge associated with the probable abandonment of the Supply Header Project of $463 million, a charge for disallowance of capitalized AFUDC due to the resolution of EGTS' 2015 FERC audit of $43 million and the write-off of certain items in connection with the GT&S Transaction of $17 million, partially offset by a decrease in services performed for Atlantic Coast Pipeline of $55 million, the absence of a charge related to a voluntary retirement program of $39 million, a decrease in services provided by affiliates of $16 million, the absence of a charge related to the abandonment of the Sweden Valley project of $13 million and the absence of Questar Pipeline Group operations from the date of the GT&S Transaction of $7 million.
Depreciation and amortization decreased $1 million for 2020 compared to 2019, primarily due to the absence of Questar Pipeline Group from the date of the GT&S Transaction of $8 million, partially offset by higher plant placed in-service of $7 million.
Property and other taxes decreased $1 million, or 1%, for 2020 compared to 2019, primarily due to the absence of Questar Pipeline Group operations from the date of the GT&S Transaction.
Interest expense increased $15 million, or 5%, for 2020 compared to 2019, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction and interest expense on Eastern Energy Gas' November 2019 senior note issuance of $23 million, partially offset by interest expense of $100 million recognized in 2019 from Cove Point's term loan borrowings that was repaid in September 2019, interest expense of $38 million recognized in 2019 from intercompany borrowings as a result of the Dominion Energy Gas Restructuring, the November 2020 disposition of Questar Pipeline Group of $3 million and lower interest expense of $3 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020.
Allowance for borrowed funds decreased $7 million, or 54%, for 2020 compared to 2019, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.
Allowance for equity funds decreased $5 million, or 28%, for 2020 compared to 2019, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.
Interest and dividend income decreased $38 million, or 36%, for 2020 compared to 2019, primarily due to interest income from Cove Point's notes receivable from DEI of $82 million recognized in 2019 that was repaid in September 2019, partially offset by interest income from DEI of $27 million that was repaid in August 2020 and the East Ohio Gas Company of $20 million that was repaid in June 2020.
Income tax (benefit) expense decreased $125 million for 2020 compared to 2019. The effective tax rate was (12)% in 2020 and 13% in 2019. The effective tax rate decreased primarily due to the impact of lower pre-tax income of $552 million driven by charges associated with the Supply Header Project, partially offset by the effects of the changes in tax status in connection with the Dominion Energy Gas Restructuring of $24 million.
Net income attributable to noncontrolling interests increased $43 million, or 36%, for 2020 compared to 2019, primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.
Liquidity and Capital Resources
As of December 31, 2021, Eastern Energy Gas' total net liquidity was $422 million as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 22 | |
Intercompany revolving credit agreement(1) | | 400 | |
| | |
| | |
| | |
| | |
| | |
Total net liquidity | | $ | 422 | |
| | |
Intercompany credit agreement: | | |
Maturity date | | 2022 |
(1)Refer to Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Eastern Energy Gas' intercompany revolving credit agreement.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2021 and 2020 were $1.1 billion and $1.3 billion, respectively. The change was primarily due to lower collections from affiliates, the November 2020 disposition of Questar Pipeline Group and the timing of payments of operating costs, partially offset by the settlement of interest rate swaps in 2020 and higher income tax receipts.
Net cash flows from operating activities for the years ended December 31, 2020 and 2019 were $1.3 billion and $1.1 billion, respectively. The change was primarily due to changes in working capital offset by the settlement of interest rate swaps.
The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2021 and 2020 were $(486) million and $3.1 billion, respectively. The change was primarily due to lower repayments of loans by affiliates of $3.1 billion, loans to affiliates of $183 million and higher funding of equity method investments of $152 million.
Net cash flows from investing activities for the years ended December 31, 2020 and 2019 were $3.1 billion and $1.2 billion, respectively. The change was primarily due to the absence of loans to affiliates of $1.9 billion and lower capital expenditures of $330 million, partially offset by lower repayments of loans by affiliates of $326 million.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2021 were $(615) million. Sources of cash totaled $346 million and consisted of proceeds from equity contributions, that included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $961 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $450 million and repayment of notes to affiliates of $9 million.
Net cash flows from financing activities for the year ended December 31, 2020 were $(4.3) billion. Sources of cash totaled $1.2 billion and consisted of proceeds from equity contributions, that included a contribution from its indirect parent BHE to Eastern Energy Gas to repay its $700 million of debt. Uses of cash totaled $5.5 billion and consisted mainly of distributions of $4.5 billion, repayments of long-term debt of $700 million and net repayments of affiliated current borrowings of $251 million as required by the GT&S Transaction.
Net cash flows from financing activities for the year ended December 31, 2019 were $(2.4) billion. Sources of cash totaled $5.3 billion and consisted mainly of proceeds from equity contributions of $3.4 billion and proceeds from long-term debt issuances of $1.9 billion. Uses of cash totaled $7.7 billion and consisted mainly of repayments of long-term debt of $4.1 billion, net repayments of affiliated current borrowings of $2.8 billion and distributions of $636 million.
Short-term Debt
As of December 31, 2020, Eastern Energy Gas had $9 million of an outstanding note payable to an affiliate at a weighted average interest rate of 0.55%. For further discussion, refer to Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Long-term Debt
Eastern Energy Gas made repayments on long-term debt totaling $500 million and $700 million during the years ended December 31, 2021 and 2020, respectively.
Future Uses of Cash
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Historical | | Forecast |
| 2019(1) | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
Natural gas transmission and storage | $ | 105 | | | $ | 112 | | | $ | 16 | | | $ | 60 | | | $ | 133 | | | $ | 324 | |
Other | 289 | | | 262 | | | 426 | | | 297 | | | 274 | | | 251 | |
Total | $ | 394 | | | $ | 374 | | | $ | 442 | | | $ | 357 | | | $ | 407 | | | $ | 575 | |
(1)Excludes capital expenditures related to entities disposed of in connection with the Dominion Energy Gas Restructuring. Refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion.
Eastern Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of non-regulated and routine capital expenditures for natural gas transmission, storage and LNG terminalling infrastructure needed to serve existing and expected demand.
Off-Balance Sheet Arrangements
Eastern Energy Gas has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on Eastern Energy Gas' Consolidated Balance Sheets as an equity investment and is increased or decreased for Eastern Energy Gas' pro-rata share of earnings or losses, respectively, less any dividends from such investments.
As of December 31, 2021, Eastern Energy Gas' investments that are accounted for under the equity method had short- and long-term debt of $310 million and an unused revolving credit facility of $10 million. As of December 31, 2021, Eastern Energy Gas' pro-rata share of such short- and long-term debt was $155 million and unused revolving credit facility was $5 million. The entire amount of Eastern Energy Gas' pro-rata share of the outstanding short- and long-term debt and unused revolving credit facility is non-recourse to Eastern Energy Gas. Although Eastern Energy Gas is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.
Material Cash Requirements
The following table summarizes Eastern Energy Gas' material cash requirements as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Periods |
| | 2022 | | 2023 - 2024 | | 2025 - 2026 | | 2027 and Thereafter | | Total |
| | | | | | | | | | |
Interest payments on long-term debt(1) | | $ | 139 | | | $ | 254 | | | $ | 174 | | | $ | 1,089 | | | $ | 1,656 | |
Natural gas supply and transportation(1) | | 41 | | | 82 | | | 40 | | | — | | | 163 | |
Total cash requirements | | $ | 180 | | | $ | 336 | | | $ | 214 | | | $ | 1,089 | | | $ | 1,819 | |
(1)Not reflected on the Consolidated Balance Sheets.
In addition, Eastern Energy Gas also has cash requirements that may affect its consolidated financial condition that arise from long-term debt (refer to Note 8), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 9) and AROs (refer to Note 11). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K for additional information.
Regulatory Matters
Eastern Energy Gas is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Eastern Energy Gas' general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of Eastern Energy Gas is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Eastern Energy Gas' ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Eastern Energy Gas has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments.
Inflation
Historically, overall inflation and changing prices in the economies where Eastern Energy Gas operates have not had a significant impact on Eastern Energy Gas' consolidated financial results. Eastern Energy Gas and its subsidiaries primarily operate under cost-of-service based rate structures administered by the FERC. Under these rate structures, Eastern Energy Gas is allowed to include prudent costs in its rates, including the impact of inflation. Eastern Energy Gas attempts to minimize the potential impact of inflation on its operations by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Eastern Energy Gas' methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Eastern Energy Gas' Summary of Significant Accounting Policies included in Eastern Energy Gas' Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Eastern Energy Gas prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Eastern Energy Gas continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Eastern Energy Gas' ability to recover its costs. Eastern Energy Gas believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $74 million and total regulatory liabilities were $685 million as of December 31, 2021. Refer to Eastern Energy Gas' Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Eastern Energy Gas' regulatory assets and liabilities.
Impairment of Goodwill and Long-Lived Assets
Eastern Energy Gas' Consolidated Balance Sheet as of December 31, 2021 includes goodwill of acquired businesses of $1.3 billion. Eastern Energy Gas evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2021. Additionally, no indicators of impairment were identified as of December 31, 2021. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. Eastern Energy Gas uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, Eastern Energy Gas incorporates current market information, as well as historical factors.
Eastern Energy Gas evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Eastern Energy Gas would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Eastern Energy Gas' results of operations.
Income Taxes
In determining Eastern Energy Gas' income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the FERC. Eastern Energy Gas' income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Eastern Energy Gas recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Eastern Energy Gas' federal, state and local income tax examinations is uncertain, Eastern Energy Gas believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Eastern Energy Gas' consolidated financial results. Refer to Eastern Energy Gas' Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Eastern Energy Gas' income taxes.
It is probable that Eastern Energy Gas will continue to pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers. As of December 31, 2021, these amounts were recognized as a net regulatory liability of $468 million and will be included in regulated rates when the temporary differences reverse.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Eastern Energy Gas' Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Eastern Energy Gas' significant market risks are primarily associated with commodity prices, interest rates, foreign currency and the extension of credit to counterparties with which Eastern Energy Gas transacts. The following discussion addresses the significant market risks associated with Eastern Energy Gas' business activities. Eastern Energy Gas has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Eastern Energy Gas' contracts accounted for as derivatives.
Commodity Price Risk
Eastern Energy Gas is exposed to the impact of market fluctuations in commodity prices. Eastern Energy Gas is principally exposed to natural gas market fluctuations primarily through fuel retained and used during the operation of the pipeline system as well as lost and unaccounted for gas. Eastern Energy Gas is exposed to the risk of fuel retention, meaning customers have a fixed fuel retention percentage assessed on transportation and storage quantities, and the pipeline bears the risk of under-recovery and benefits from any over-recovery of volumes. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, facility availability, customer usage, storage and transportation constraints. Eastern Energy Gas does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Eastern Energy Gas uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply quantities or sell future supply quantities generally at fixed prices. Eastern Energy Gas does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices.
Interest Rate Risk
Eastern Energy Gas is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Eastern Energy Gas manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Eastern Energy Gas' fixed-rate long-term debt does not expose Eastern Energy Gas to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Eastern Energy Gas were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Eastern Energy Gas' short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Note 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Eastern Energy Gas' long-term debt.
As of December 31, 2021, Eastern Energy Gas had no short- or long-term variable-rate obligations that expose Eastern Energy Gas to the risk of increased interest expense in the event of increases in short-term interest rates. As of December 31, 2020, Eastern Energy Gas had short- and long-term variable-rate obligations totaling $509 million that expose Eastern Energy Gas to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Eastern Energy Gas' annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2020.
Eastern Energy Gas also uses interest rate derivatives, including forward starting swaps, interest rate swaps and interest rate lock agreements to manage interest rate risk. As of December 31, 2021, Eastern Energy Gas had no aggregate notional amounts of these interest rate swaps outstanding. As of December 31, 2020, Eastern Energy Gas had $500 million in aggregate notional amounts of these interest rate swaps outstanding. A hypothetical 10% decrease in market interest rates would not have a material effect on the fair value of Eastern Energy Gas' interest rate swaps as of December 31, 2020.
Eastern Energy Gas holds foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, 2021 and 2020, Eastern Energy Gas had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of Eastern Energy Gas' foreign currency swaps as of December 31, 2021 and 2020.
The impact of a change in interest rates on the Eastern Energy Gas' interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.
Credit Risk
Eastern Energy Gas is exposed to counterparty credit risk associated with natural gas transportation and storage service contracts with utilities, natural gas producers, power generators, industrials, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Eastern Energy Gas' counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Eastern Energy Gas analyzes the financial condition of each wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate counterparty credit risk, Eastern Energy Gas obtains third-party guarantees, letters of credit, financial guarantee bonds and cash deposits. If required, Eastern Energy Gas exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Eastern Energy Gas' gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. As of December 31, 2021, Eastern Energy Gas' credit exposure totaled $40 million. Of this amount, investment grade counterparties, including those internally rated, represented 92%, and no single counterparty, whether investment grade or non-investment grade, exceeded $6 million of exposure.
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eastern Energy Gas Holdings, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Eastern Energy Gas as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Eastern Energy Gas' management. Our responsibility is to express an opinion on Eastern Energy Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Eastern Energy Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Eastern Energy Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Eastern Energy Gas' internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Impact of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
Eastern Energy Gas, through its subsidiaries, is subject to rate regulation by the Federal Energy Regulatory Commission (the "FERC"), which has jurisdiction with respect to the rates of interstate natural gas transmission companies. Management has determined its rate regulated subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets; regulatory liabilities; operating revenue; operations and maintenance expense; and depreciation and amortization expense; and income tax expense (benefit).
Revenue provided by the Eastern Energy Gas interstate natural gas transmission operations is based primarily on rates approved by the FERC. Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. Eastern Energy Gas continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Eastern Energy Gas' ability to recover its costs. The evaluation reflects the current political and regulatory climate. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss).
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the FERC, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the FERC included the following, among others:
•We evaluated the Eastern Energy Gas disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the FERC, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC's treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory assets and liability balances for completeness.
•For regulatory matters in process, we inspected Eastern Energy Gas' filings with the FERC, and the filings with the FERC by intervenors that may impact Eastern Energy Gas' future rates for any evidence that might contradict management's assertions.
•We read and analyzed the minutes of the Board of Directors of Berkshire Hathaway Energy and the Board of Directors of Eastern Energy Gas, for discussions of changes in legal, regulatory, or business factors which could impact management's conclusions with respect to the impacted account balances and disclosures of rate regulation.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 2022
We have served as Eastern Energy Gas' auditor since 2012.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 22 | | | $ | 35 | |
Restricted cash and cash equivalents | 17 | | | 13 | |
Trade receivables, net | 183 | | | 177 | |
Receivables from affiliates | 54 | | | 139 | |
Other receivables | 9 | | | 51 | |
Inventories | 122 | | | 119 | |
Prepayments | 76 | | | 60 | |
Natural gas imbalances | 100 | | | 26 | |
Other current assets | 38 | | | 36 | |
Total current assets | 621 | | | 656 | |
| | | |
Property, plant and equipment, net | 10,200 | | | 10,144 | |
Goodwill | 1,286 | | | 1,286 | |
| | | |
Investments | 412 | | | 244 | |
| | | |
Other assets | 129 | | | 291 | |
| | | |
Total assets | $ | 12,648 | | | $ | 12,621 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 79 | | | $ | 71 | |
Accounts payable to affiliates | 38 | | | 39 | |
Accrued interest | 19 | | | 19 | |
Accrued property, income and other taxes | 89 | | | 29 | |
Accrued employee expenses | 13 | | | 23 | |
Notes payable to affiliates | — | | | 9 | |
Regulatory liabilities | 40 | | | 40 | |
Asset retirement obligations | 33 | | | 36 | |
Current portion of long-term debt | — | | | 500 | |
Other current liabilities | 54 | | | 48 | |
Total current liabilities | 365 | | | 814 | |
| | | |
Long-term debt | 3,906 | | | 3,925 | |
| | | |
| | | |
Regulatory liabilities | 645 | | | 669 | |
| | | |
Other long-term liabilities | 238 | | | 218 | |
Total liabilities | 5,154 | | | 5,626 | |
| | | |
Commitments and contingencies (Note 14) | 0 | | 0 |
| | | |
Equity: | | | |
Members' equity: | | | |
| | | |
Membership interests | 3,501 | | | 2,957 | |
| | | |
| | | |
Accumulated other comprehensive loss, net | (43) | | | (53) | |
Total members' equity | 3,458 | | | 2,904 | |
Noncontrolling interests | 4,036 | | | 4,091 | |
Total equity | 7,494 | | | 6,995 | |
| | | |
Total liabilities and equity | $ | 12,648 | | | $ | 12,621 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Operating revenue | $ | 1,870 | | | $ | 2,090 | | | $ | 2,169 | |
| | | | | |
Operating expenses: | | | | | |
| | | | | |
Cost of gas | 12 | | | 24 | | | 9 | |
Operations and maintenance | 515 | | | 1,142 | | | 748 | |
Depreciation and amortization | 328 | | | 366 | | | 367 | |
Property and other taxes | 149 | | | 140 | | | 141 | |
| | | | | |
Total operating expenses | 1,004 | | | 1,672 | | | 1,265 | |
| | | | | |
Operating income | 866 | | | 418 | | | 904 | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (151) | | | (339) | | | (324) | |
Allowance for borrowed funds | 2 | | | 6 | | | 13 | |
Allowance for equity funds | 7 | | | 13 | | | 18 | |
Interest and dividend income | — | | | 67 | | | 105 | |
| | | | | |
Other, net | 1 | | | 42 | | | 43 | |
Total other income (expense) | (141) | | | (211) | | | (145) | |
| | | | | |
Income from continuing operations before income tax expense (benefit) and equity income | 725 | | | 207 | | | 759 | |
Income tax expense (benefit) | 117 | | | (24) | | | 101 | |
Equity income | 44 | | | 42 | | | 43 | |
Net income from continuing operations | 652 | | | 273 | | | 701 | |
Net income from discontinued operations(1) | — | | | — | | | 141 | |
Net income | 652 | | | 273 | | | 842 | |
Net income attributable to noncontrolling interests | 390 | | | 164 | | | 121 | |
Net income attributable to Eastern Energy Gas | $ | 262 | | | $ | 109 | | | $ | 721 | |
(1)Includes income tax expense of $33 million for the year ended December 31, 2019.
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 652 | | | $ | 273 | | | $ | 842 | |
| | | | | |
Other comprehensive income (loss), net of tax: | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $—, $40 and $15 | 6 | | | 94 | | | 38 | |
| | | | | |
| | | | | |
Unrealized gains (losses) on cash flow hedges, net of tax of $1, $10 and $(20) | 9 | | | 30 | | | (56) | |
Total other comprehensive income (loss), net of tax | 15 | | | 124 | | | (18) | |
| | | | | |
Comprehensive income | 667 | | | 397 | | | 824 | |
Comprehensive income attributable to noncontrolling interests | 395 | | | 154 | | | 120 | |
Comprehensive income attributable to Eastern Energy Gas | $ | 272 | | | $ | 243 | | | $ | 704 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | | Predecessor | | | | | | Membership | | Comprehensive | | Noncontrolling | | Total |
| | | Equity | | | | | | Interests | | Loss, Net | | Interests | | Equity |
| | | | | | | | | | | | | | | |
Balance, December 31, 2018 | | | $ | 1,804 | | | | | | | $ | 4,566 | | | $ | (169) | | | $ | 2,664 | | | $ | 8,865 | |
Net income | | | 232 | | | | | | | 489 | | | — | | | 121 | | | 842 | |
Other comprehensive loss | | | — | | | | | | | — | | | (17) | | | (1) | | | (18) | |
Contributions | | | 3,385 | | | | | | | — | | | — | | | — | | | 3,385 | |
Distributions | | | (457) | | | | | | | — | | | — | | | (179) | | | (636) | |
Acquisition of public interest in Northeast Midstream | | | 1,181 | | | | | | | — | | | — | | | (1,221) | | | (40) | |
Dominion Energy Gas Restructuring | | | (6,145) | | | | | | | 3,978 | | | (1) | | | — | | | (2,168) | |
Other equity transactions | | | — | | | | | | | (2) | | | — | | | 1 | | | (1) | |
Balance, December 31, 2019 | | | — | | | | | | | 9,031 | | | (187) | | | 1,385 | | | 10,229 | |
Net income | | | — | | | | | | | 109 | | | — | | | 164 | | | 273 | |
Other comprehensive income (loss) | | | — | | | | | | | — | | | 134 | | | (10) | | | 124 | |
Contributions | | | — | | | | | | | 1,223 | | | — | | | — | | | 1,223 | |
Distributions | | | — | | | | | | | (4,282) | | | — | | | (216) | | | (4,498) | |
Distribution of Questar Pipeline Group | | | — | | | | | | | (699) | | | — | | | — | | | (699) | |
Distribution of 50% interest in Cove Point | | | — | | | | | | | (2,765) | | | — | | | 2,765 | | | — | |
Acquisition of Eastern Energy Gas by BHE | | | — | | | | | | | 343 | | | — | | | — | | | 343 | |
Other equity transactions | | | — | | | | | | | (3) | | | — | | | 3 | | | — | |
Balance, December 31, 2020 | | | — | | | | | | | 2,957 | | | (53) | | | 4,091 | | | 6,995 | |
Net income | | | — | | | | | | | 262 | | | — | | | 390 | | | 652 | |
Other comprehensive income | | | — | | | | | | | — | | | 10 | | | 5 | | | 15 | |
Contributions | | | — | | | | | | | 419 | | | — | | | — | | | 419 | |
Distributions | | | — | | | | | | | (137) | | | — | | | (450) | | | (587) | |
| | | | | | | | | | | | | | | |
Balance, December 31, 2021 | | | $ | — | | | | | | | $ | 3,501 | | | $ | (43) | | | $ | 4,036 | | | $ | 7,494 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income | $ | 652 | | | $ | 273 | | | $ | 842 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
(Gains) losses on other items, net | (3) | | | 531 | | | 21 | |
Depreciation and amortization | 328 | | | 366 | | | 445 | |
Allowance for equity funds | (7) | | | (13) | | | (18) | |
Equity loss, net of distributions | — | | | 35 | | | 31 | |
Changes in regulatory assets and liabilities | (20) | | | (37) | | | (74) | |
Deferred income taxes | 186 | | | (5) | | | (3) | |
Other, net | (19) | | | 23 | | | 61 | |
Changes in other operating assets and liabilities: | | | | | |
Trade receivables and other assets | 7 | | | 346 | | | 115 | |
Derivative collateral, net | 10 | | | (140) | | | 7 | |
Pension and other postretirement benefit plans | — | | | (88) | | | (139) | |
Accrued property, income and other taxes | (30) | | | 23 | | | (53) | |
Accounts payable and other liabilities | (12) | | | (40) | | | (173) | |
Net cash flows from operating activities | 1,092 | | | 1,274 | | | 1,062 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (442) | | | (374) | | | (704) | |
| | | | | |
| | | | | |
Loans to affiliates | (183) | | | — | | | (1,872) | |
Repayment of loans by affiliates | 305 | | | 3,422 | | | 3,748 | |
Equity method investments | (154) | | | (2) | | | (4) | |
Other, net | (12) | | | 18 | | | (18) | |
Net cash flows from investing activities | (486) | | | 3,064 | | | 1,150 | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from long-term debt | — | | | — | | | 1,895 | |
Repayments of long-term debt | (500) | | | (700) | | | (4,141) | |
Net (repayments of) proceeds from short-term debt | — | | | (62) | | | 52 | |
Repayment of affiliated current borrowings, net | (9) | | | (251) | | | (2,837) | |
Credit facility repayments | — | | | — | | | (73) | |
Proceeds from equity contributions | 346 | | | 1,223 | | | 3,385 | |
Distributions to parent | — | | | (4,323) | | | (457) | |
Distributions to noncontrolling interests | (450) | | | (216) | | | (179) | |
Other, net | (2) | | | — | | | (16) | |
Net cash flows from financing activities | (615) | | | (4,329) | | | (2,371) | |
| | | | | |
Net change in cash and cash equivalents and restricted cash | (9) | | | 9 | | | (159) | |
Cash and cash equivalents and restricted cash at beginning of period | 48 | | | 39 | | | 198 | |
Cash and cash equivalents and restricted cash at end of period | $ | 39 | | | $ | 48 | | | $ | 39 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)Organization and Operations
Eastern Energy Gas Holdings, LLC is a holding company, and together with its subsidiaries ("Eastern Energy Gas") conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipeline and underground storage operations in the eastern region of the United States and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-mile FERC-regulated interstate natural gas transportation pipeline. On November 1, 2020, Berkshire Hathaway Energy Company ("BHE") completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") (the "GT&S Transaction"). As a result of the GT&S Transaction, Eastern Energy Gas became an indirect wholly owned subsidiary of BHE. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). See Note 3 for more information regarding the GT&S Transaction.
(2) Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Eastern Energy Gas and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Eastern Energy Gas prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in restricted cash and cash equivalents on the Consolidated Balance Sheets.
Investments
Eastern Energy Gas utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, Eastern Energy Gas records the investment at cost and subsequently increases or decreases the carrying value of the investment by Eastern Energy Gas' share of the net earnings or losses and other comprehensive income ("OCI") of the investee. Eastern Energy Gas records dividends or other equity distributions as reductions in the carrying value of the investment.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Eastern Energy Gas' assessment of the collectability of amounts owed to Eastern Energy Gas by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Eastern Energy Gas primarily utilizes credit loss history. However, Eastern Energy Gas may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The changes in the balance of the allowance for credit losses, which is included in trades receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Beginning balance | $ | 5 | | | $ | 2 | | | $ | — | |
Charged to operating costs and expenses, net | 1 | | | 4 | | | 2 | |
Write-offs, net | — | | | (1) | | | — | |
Ending balance | $ | 6 | | | $ | 5 | | | $ | 2 | |
Derivatives
Eastern Energy Gas employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of gas on the Consolidated Statements of Operations.
For Eastern Energy Gas' derivatives not designated as hedging contracts, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for derivatives related to natural gas sales contracts; and other, net for interest rate swap derivatives.
For Eastern Energy Gas' derivatives designated as hedging contracts, Eastern Energy Gas formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Eastern Energy Gas formally documents hedging activity by transaction type and risk management strategy. For derivative instruments that are accounted for as cash flow hedges or fair value hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. Eastern Energy Gas discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies and are determined using the average cost method.
Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Eastern Energy Gas values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Eastern Energy Gas from other parties are reported in current assets and imbalances that Eastern Energy Gas owes to other parties are reported in other current liabilities on the Consolidated Balance Sheets.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Eastern Energy Gas capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on estimated useful lives. Depreciation studies are completed by Eastern Energy Gas to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the FERC. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when Eastern Energy Gas retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by Eastern Energy Gas as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, Eastern Energy Gas is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
Eastern Energy Gas recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Eastern Energy Gas' AROs are primarily related to the obligations associated with its natural gas pipeline and storage well assets. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For Eastern Energy Gas, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment
Eastern Energy Gas evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets. See Note 6 for more information.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. Eastern Energy Gas evaluates goodwill for impairment at least annually. Prior to the GT&S Transaction, Eastern Energy Gas evaluated goodwill for impairment as of April 1. As a result of the GT&S Transaction, Eastern Energy Gas now completes its annual reviews as of October 31 to align with BHE's policy. When evaluating goodwill for impairment, Eastern Energy Gas estimates the fair value of its reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the excess is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2021, 2020 and 2019, Eastern Energy Gas did not record any goodwill impairments.
Eastern Energy Gas records goodwill adjustments for changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.
Revenue Recognition
Eastern Energy Gas uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Eastern Energy Gas expects to be entitled in exchange for those goods or services. Eastern Energy Gas records sales and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
A majority of Eastern Energy Gas' Customer Revenue is derived from tariff-based sales arrangements approved by the FERC. These tariff-based revenues are mainly comprised of natural gas transmission and storage services and have performance obligations which are satisfied over time as services are provided. Eastern Energy Gas' revenue that is nonregulated primarily relates to LNG terminalling services.
Revenue recognized is equal to what Eastern Energy Gas has the right to invoice as it corresponds directly with the value to the customer of Eastern Energy Gas' performance to date and includes billed and unbilled amounts. As of December 31, 2021 and 2020, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $36 million and $95 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In the event one of the parties to a contract has performed before the other, Eastern Energy Gas would recognize a contract asset or contract liability depending on the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas has recognized contract assets of $19 million and $29 million as of December 31, 2021 and 2020, respectively, and $18 million and $19 million of contract liabilities as of December 31, 2021 and 2020, respectively, due to Eastern Energy Gas' performance on certain contracts.
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Prior to the GT&S Transaction, DEI included Eastern Energy Gas in its consolidated United States federal income tax return. Subsequent to the GT&S Transaction, Berkshire Hathaway includes Eastern Energy Gas in its consolidated United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provision for income taxes has been computed on a stand-alone return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that Eastern Energy Gas' regulated businesses deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Eastern Energy Gas recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Segment Information
Eastern Energy Gas currently has 1 segment, which includes its natural gas pipeline, storage and LNG operations.
(3) Business Acquisitions and Dispositions
Acquisition of Eastern Energy Gas by BHE
In July 2020, DEI entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy Gas and a 25% limited partnership interest in Cove Point, to BHE. Approval of the transaction under the Hart-Scott-Rodino Act was not obtained within 75 days and DEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the GT&S Transaction and the proposed sale of Dominion Energy Questar Pipeline, LLC and related entities ("the Questar Pipeline Group") by DEI to BHE pursuant to a purchase and sale agreement entered into on October 5, 2020 ("Q-Pipe Transaction"). In July 2021, Dominion Energy Questar Corporation ("Dominion Questar") and DEI delivered a written notice to BHE stating that BHE and Dominion Questar mutually elected to terminate the Q-Pipe Transaction. Prior to the completion of the GT&S Transaction, Eastern Energy Gas finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in Cove Point to DEI. This restructuring was accounted for by Eastern Energy Gas as a reorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business.
In November 2020, the GT&S Transaction was completed and Eastern Energy Gas, with the exception of the Questar Pipeline Group as discussed above, became an indirect wholly-owned subsidiary of BHE. DEI retained a 50% noncontrolling interest in Cove Point as well as the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations sold and relating to services provided before closing. The GT&S Transaction was treated as a deemed asset sale for federal and state income tax purposes and all deferred taxes at Eastern Energy Gas were reset to reflect financial and tax basis differences as of November 1, 2020. See Notes 9 and 16 for more information on the GT&S Transaction.
Eastern Energy Gas recorded a distribution of net assets of $699 million, including goodwill of $185 million and $41 million of cash, for the distribution of the Questar Pipeline Group to DEI and recorded an approximately $2.8 billion increase in noncontrolling interests for DEI's retained 50% noncontrolling interest in Cove Point. Additionally, in accordance with the terms of the GT&S Transaction, DEI retained certain assets and liabilities associated with Eastern Energy Gas and settled all affiliated balances. As a result, Eastern Energy Gas recorded a contribution for the reset of deferred taxes of $1.3 billion, net of distributions of $895 million related to the pension and other postretirement employee benefit plans retained by DEI and $107 million related to the settlement of affiliated balances.
Dominion Energy Gas Restructuring
The acquisition of CPMLP Holdings Company, LLC ("DCP") and Eastern MLP Holding Company II, LLC ("DMLPHCII") from, and the disposition of the East Ohio Gas Company ("East Ohio") and Eastern Gathering and Processing, Inc. ("EGP") to, DEI by Eastern Energy Gas on November 6, 2019 ("Dominion Energy Gas Restructuring") was considered to be a reorganization of entities under common control. As a result, Eastern Energy Gas' basis in DCP and DMLPHCII, which included the general partner of Northeast Midstream Partners, LP ("Northeast Midstream"), a controlling 75% interest in Cove Point, Carolina Gas Transmission, LLC, Questar Pipeline Group, a 50% noncontrolling interest in White River Hub, LLC ("White River Hub") and a 25.93% noncontrolling interest in Iroquois, is equal to DEI's cost basis in the assets and liabilities of such entities since the applicable inception dates of common control. In November 2019, following completion of the Dominion Energy Gas Restructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Eastern Energy Gas and therefore are consolidated by Eastern Energy Gas. The accompanying Consolidated Financial Statements and Notes of Eastern Energy Gas have been retrospectively adjusted to include the historical results and financial position of DCP and DMLPHCII. The 25% interest in Cove Point retained by DEI, and subsequently sold to Brookfield Super-Core Infrastructure Partners ("Brookfield") in December 2019, and the non-DEI held interest in Northeast Midstream (through January 2019) are reflected as noncontrolling interest.
The Dominion Energy Gas Restructuring included the disposition of East Ohio and EGP by Eastern Energy Gas in November 2019. This restructuring represented a strategic shift in the operations of Eastern Energy Gas as Eastern Energy Gas' operations consist of LNG import/export and storage and regulated gas transmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes of Eastern Energy Gas have been retrospectively adjusted to include the historical results and financial position of East Ohio and EGP as discontinued operations until November 2019. As the Dominion Energy Gas Restructuring was considered to be a reorganization of entities under common control, Eastern Energy Gas reflected the disposition as an equity transaction. The following table represents selected information regarding the results of operations of East Ohio, which are reported as discontinued operations in Eastern Energy Gas' Consolidated Statements of Operations (in millions):
| | | | | |
| Period Ended November 6, 2019 |
Operating revenue | $ | 594 | |
Depreciation and amortization | 73 | |
Other operating expenses | 399 | |
Other income (expense), net | 28 | |
Income tax expense | 26 | |
Net income from discontinued operations | $ | 124 | |
Capital expenditures and significant noncash items relating to East Ohio included the following (in millions):
| | | | | |
| Period Ended November 6, 2019 |
Capital expenditures | $ | 299 | |
Significant noncash items: | |
Charge related to a voluntary retirement program | 20 |
Accrued capital expenditures | 2 |
The following table represents selected information regarding the results of operations of EGP, which are reported as discontinued operations in Eastern Energy Gas' Consolidated Statements of Operations (in millions):
| | | | | |
| Period Ended November 6, 2019 |
Operating revenue | $ | 125 | |
Depreciation and amortization | 4 | |
Other operating expenses | 97 | |
Income tax expense | 7 | |
Net income from discontinued operations | $ | 17 | |
Capital expenditures of EGP included the following (in millions):
| | | | | |
| Period Ended November 6, 2019 |
Capital expenditures | $ | 11 | |
| |
(1) | Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments. |
(17) Unaudited Quarterly Operating Results
(4) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
| | | | | |
Interstate natural gas pipeline assets | 21 - 44 years | | $ | 8,675 | | | $ | 8,382 | |
Intangible plant | 5 - 10 years | | 110 | | | 115 | |
Utility plant in-service | | | 8,785 | | | 8,497 | |
Accumulated depreciation and amortization | | | (2,901) | | | (2,759) | |
Utility plant in-service, net | | | 5,884 | | | 5,738 | |
| | | | | |
Nonutility Plant: | | | | | |
| | | | | |
LNG facility | 40 years | | 4,475 | | | 4,454 | |
Intangible plant | 14 years | | 25 | | | 25 | |
Nonutility plant in-service | | | 4,500 | | | 4,479 | |
Accumulated depreciation and amortization | | | (423) | | | (283) | |
Nonutility plant in-service, net | | | 4,077 | | | 4,196 | |
| | | | | |
Plant, net | | | 9,961 | | | 9,934 | |
Construction work- in-progress | | | 239 | | | 210 | |
Property, plant and equipment, net | | | $ | 10,200 | | | $ | 10,144 | |
Construction work-in-progress includes $209 million and $196 million as of December 31, 2021 and 2020, respectively, related to the construction of utility plant.
(5) Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, Eastern Energy Gas, as a tenant in common, has undivided interests in jointly owned transmission and storage facilities. Eastern Energy Gas accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners primarily based on their percentage of ownership. Operating costs and expenses on the Consolidated Statements of Operations include Eastern Energy Gas' share of the expenses of these facilities.
The amounts shown in the table below represent Eastern Energy Gas' share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2021 (dollars in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Accumulated | | Construction |
| Eastern Energy Gas' | | Facility in | | Depreciation and | | Work-in- |
| Share | | Service | | Amortization | | Progress |
| | | | | | | |
Ellisburg Pool | 39 | % | | $ | 31 | | | $ | 11 | | | $ | 1 | |
Ellisburg Station | 50 | | | 26 | | | 8 | | | 1 | |
Harrison | 50 | | | 53 | | | 18 | | | — | |
Leidy | 50 | | | 132 | | | 46 | | | 7 | |
Oakford | 50 | | | 200 | | | 68 | | | 2 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total | | | $ | 442 | | | $ | 151 | | | $ | 11 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2018 | | 2018 | | 2018 | | 2018 |
Regulated electric operating revenue | $ | 181 |
| | $ | 169 |
| | $ | 225 |
| | $ | 177 |
|
Regulated natural gas operating revenue | 41 |
| | 19 |
| | 14 |
| | 29 |
|
Operating income | 47 |
| | 19 |
| | 56 |
| | 30 |
|
Net income | 34 |
| | 7 |
| | 35 |
| | 16 |
|
| | | | | | | |
| Three-Month Periods Ended |
| March 31, | | June 30, | | September 30, | | December 31, |
| 2017 | | 2017 | | 2017 | | 2017 |
Regulated electric operating revenue | $ | 159 |
| | $ | 160 |
| | $ | 215 |
| | $ | 179 |
|
Regulated natural gas operating revenue | 34 |
| | 17 |
| | 15 |
| | 33 |
|
Operating income | 46 |
| | 36 |
| | 75 |
| | 41 |
|
Net income | 24 |
| | 17 |
| | 44 |
| | 24 |
|
(6) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future regulated rates. Eastern Energy Gas' regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| Weighted Average Remaining Life | | 2021 | | 2020 |
| | | | | |
Employee benefit plans(1) | 14 years | | $ | 62 | | | $ | 70 | |
| | | | | |
| | | | | |
Other | Various | | 12 | | | 12 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Total regulatory assets | | | $ | 74 | | | $ | 82 | |
| | | | | |
Reflected as: | | | | | |
Other current assets | | | $ | 6 | | | $ | 8 | |
Other assets | | | 68 | | | 74 | |
Total regulatory assets | | | $ | 74 | | | $ | 82 | |
(1)Represents costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain rate-regulated subsidiaries.
Eastern Energy Gas had regulatory assets not earning a return on investment of $8 million and $10 million as of December 31, 2021 and 2020, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts expected to be returned to customers in future periods. Eastern Energy Gas' regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | | | |
| | | | | |
| Weighted Average Remaining Life | | 2021 | | 2020 |
| | | | | |
Income taxes refundable through future rates(1) | Various | | $ | 468 | | | $ | 473 | |
Other postretirement benefit costs(2) | Various | | 116 | | | 115 | |
Cost of removal(3) | 44 years | | 73 | | | 88 | |
| | | | | |
Other | Various | | 28 | | | 33 | |
| | | | | |
Total regulatory liabilities | | | $ | 685 | | | $ | 709 | |
| | | | | |
Reflected as: | | | | | |
Current liabilities | | | $ | 40 | | | $ | 40 | |
Noncurrent liabilities | | | 645 | | | 669 | |
Total regulatory liabilities | | | $ | 685 | | | $ | 709 | |
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.
(3)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
Regulatory Matters
Eastern Gas Transmission and Storage, Inc.
In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.
In July 2017, the FERC audit staff communicated to EGTS that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) charge for disallowance of capitalized AFUDC, recorded within operations and maintenance expense in the Consolidated Statement of Operations. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized AFUDC, which resulted in a reduction to the estimated charge of $11 million ($8 million after-tax) that was recorded in operations and maintenance expense in the Consolidated Statement of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.
In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 Eastern Energy Gas recorded a charge of $482 million ($359 million after-tax) in operations and maintenance expense in its Consolidated Statement of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million ARO. In the third quarter of 2020, Eastern Energy Gas recorded an additional charge of $10 million ($7 million after-tax) associated with the probable abandonment of a significant portion of the project and a $29 million ($20 million after-tax) benefit from a revision to the previously established ARO, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statement of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.
In January 2018, EGTS filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the Sweden Valley project. In June 2019, EGTS withdrew its application for the project due to certain regulatory delays. As a result of the project abandonment, during the second quarter of 2019, EGTS recorded a charge of $13 million ($10 million after-tax), included in operations and maintenance expenses in the Consolidated Statement of Operations.
Cove Point
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding.Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020.The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.
(7) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Investments: | | | |
Investment funds | $ | 13 | | | $ | — | |
| | | |
Equity method investments: | | | |
Iroquois | 399 | | | 244 | |
Total investments | 412 | | | 244 | |
| | | |
Restricted cash and cash equivalents: | | | |
Customer deposits | 17 | | | 13 | |
Total restricted cash and cash equivalents | 17 | | | 13 | |
| | | |
Total investments and restricted cash and cash equivalents | $ | 429 | | | $ | 257 | |
| | | |
Reflected as: | | | |
Current assets | $ | 17 | | | $ | 13 | |
Noncurrent assets | 412 | | | 244 | |
Total investments and restricted cash and cash equivalents | $ | 429 | | | $ | 257 | |
Equity Method Investments
Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut. Prior to the GT&S Transaction, Eastern Energy Gas, through the Questar Pipeline Group, owned 50% of White River Hub, which owns and operates a natural gas pipeline in northwest Colorado.
As of both December 31, 2021 and 2020, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $130 million. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas made contributions of $154 million in 2021. Eastern Energy Gas received distributions from its investments of $44 million, $77 million and $74 million for the years ended December 31, 2021, 2020 and 2019, respectively.
(8) Long-term Debt
On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $1.6 billion of its issued and outstanding third party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or loss recognized in the Consolidated Financial Statements.
Eastern Energy Gas' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars and euros in millions):
| | | | | | | | | | | | | | | | | |
| Par Value | | 2021 | | 2020 |
| | | | | |
Eastern Energy Gas: | | | | | |
Variable-rate Senior Notes, due 2021(1) | $ | — | | | $ | — | | | $ | 500 | |
| | | | | |
2.875% Senior Notes, due 2023 | 250 | | | 250 | | | 249 | |
3.55% Senior Notes, due 2023 | 400 | | | 399 | | | 399 | |
2.50% Senior Notes, due 2024 | 600 | | | 597 | | | 596 | |
3.60% Senior Notes, due 2024 | 339 | | | 338 | | | 448 | |
3.32% Senior Notes, due 2026 (€250)(2) | 284 | | | 283 | | | 304 | |
| | | | | |
3.00% Senior Notes, due 2029 | 174 | | | 173 | | | 594 | |
3.80% Senior Notes, due 2031 | 150 | | | 150 | | | 150 | |
| | | | | |
| | | | | |
4.80% Senior Notes, due 2043 | 54 | | | 53 | | | 395 | |
4.60% Senior Notes, due 2044 | 56 | | | 56 | | | 493 | |
3.90% Senior Notes, due 2049 | 27 | | | 26 | | | 297 | |
| | | | | |
EGTS: | | | | | |
3.60% Senior Notes, due 2024 | 111 | | | 110 | | | — | |
3.00% Senior Notes, due 2029 | 426 | | | 422 | | | — | |
4.80% Senior Notes, due 2043 | 346 | | | 341 | | | — | |
4.60% Senior Notes, due 2044 | 444 | | | 437 | | | — | |
3.90% Senior Notes, due 2049 | 273 | | | 271 | | | — | |
Total long-term debt | $ | 3,934 | | | $ | 3,906 | | | $ | 4,425 | |
| | | | | |
Reflected as: | | | | | |
Current portion of long-term debt | | | $ | — | | | $ | 500 | |
Long-term debt | | | 3,906 | | | 3,925 | |
Total long-term debt | | | $ | 3,906 | | | $ | 4,425 | |
(1)The senior notes had variable interest rates based on LIBOR plus an applicable spread. Eastern Energy Gas entered into an interest rate swap that fixed the interest rate on 100% of the notes. The fixed interest rate as of December 31, 2020 was 3.46% (including a 0.60% margin).
(2)The senior notes are denominated in Euros with an outstanding principal balance of €250 million and a fixed interest rate of 1.45%. Eastern Energy Gas has entered into cross currency swaps that fix USD payments for 100% of the notes. The fixed USD outstanding principal when combined with the swaps is $280 million, with fixed interest rates at both December 31, 2021 and 2020 that averaged 3.32%.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt for the years beginning January 1, 2022 and thereafter, are as follows (in millions):
| | | | | |
2022 | $ | — | |
2023 | 650 | |
2024 | 1,050 | |
2025 | — | |
2026 | 284 | |
2027 and thereafter | 1,950 | |
Total | 3,934 | |
Unamortized premium, discount and debt issuance cost | (28) | |
Total | $ | 3,906 | |
(9) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Current: | | | | | |
Federal | $ | (47) | | | $ | (20) | | | $ | 130 | |
State | (21) | | | 1 | | | 17 | |
| (68) | | | (19) | | | 147 | |
Deferred: | | | | | |
Federal | 129 | | | 23 | | | (36) | |
State | 56 | | | (28) | | | (10) | |
| 185 | | | (5) | | | (46) | |
| | | | | |
Total | $ | 117 | | | $ | (24) | | | $ | 101 | |
Income tax expense reported in discontinued operations for the year ended December 31, 2019 was $33 million.
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows for the years ended December 31:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % |
| | | | | |
State income tax, net of federal income tax benefit | 3 | | | (13) | | | 1 | |
| | | | | |
| | | | | |
| | | | | |
Equity interest | 1 | | | 4 | | | 1 | |
Effects of ratemaking | 1 | | | (2) | | | (1) | |
| | | | | |
| | | | | |
Change in tax status | — | | | (9) | | | (4) | |
| | | | | |
AFUDC-equity | — | | | (1) | | | (1) | |
Noncontrolling interest | (11) | | | (16) | | | (3) | |
Write-off of regulatory assets | — | | | 3 | | | — | |
Other, net | 1 | | | 1 | | | (1) | |
Effective income tax rate | 16 | % | | (12) | % | | 13 | % |
For the year ended December 31, 2021, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by the absence of tax on noncontrolling interest. The GT&S Transaction resulted in a change of Cove Point's noncontrolling interest from 25% to 75% as of November 1, 2020.
The net deferred income tax (liability) asset consists of the following as of December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
Deferred income tax assets: | | | |
Federal and state carryforwards | $ | 7 | | | $ | — | |
| | | |
| | | |
Employee benefits | 33 | | | 30 | |
Intangibles | 150 | | | 148 | |
Derivatives and hedges | 16 | | | 18 | |
| | | |
| | | |
Other | 9 | | | 4 | |
Total deferred income tax assets | 215 | | | 200 | |
| | | |
| | | |
| | | |
Deferred income tax liabilities: | | | |
Property related items | (129) | | | (52) | |
| | | |
Partnership investments | (49) | | | (19) | |
Debt exchange | (60) | | | — | |
| | | |
Deferred state income taxes | (16) | | | — | |
Debt issuance discount | (7) | | | (8) | |
| | | |
Other | (9) | | | (2) | |
Total deferred income tax liabilities | (270) | | | (81) | |
Net deferred income tax (liability) asset (1) | $ | (55) | | | $ | 119 | |
(1)Net deferred income tax liability as of December 31, 2021 is presented in other assets and other long-term liabilities in the Consolidated Balance Sheet. Net deferred income tax asset as of December 31, 2020 is presented in other assets in the Consolidated Balance Sheet.
The significant change in net deferred taxes is due to higher tax depreciation due to the GT&S Transaction being treated as a deemed asset sale for federal and state income tax purposes, the debt exchange at EGTS and partnership income from Cove Point.
As of December 31, 2021, Eastern Energy Gas' $7 million of state net operating losses, entirely related to West Virginia, can be carried forward indefinitely.
Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. As a result of the GT&S Transaction, DEI retained the rights and obligations of Eastern Energy Gas' federal and state income tax returns through October 31, 2020. The statute of limitations for Eastern Energy Gas' income tax returns filed for periods after November 1, 2020 remain open for examination for federal and Connecticut, Maryland, North Carolina, Pennsylvania, South Carolina, Virginia, and West Virginia.
A reconciliation of the beginning and ending balances of Eastern Energy Gas' net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | — | | | $ | 2 | |
| | | |
Additions for tax positions of prior years | — | | | 5 | |
| | | |
Reductions for unrecognized tax benefits retained by DEI | — | | | (7) | |
| | | |
Ending balance | $ | — | | | $ | — | |
As of December 31, 2021, Eastern Energy Gas has no unrecognized tax benefits that would have an impact on the effective tax rate. As part of the GT&S Transaction, DEI has retained all pre-close unrecognized tax benefits.
(10) Employee Benefit Plans
As discussed in Note 3, in November 2020, the GT&S Transaction was completed and the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations sold and relating to services provided before closing were retained by DEI. As a result, just prior to completing the sale, net benefit plan assets of $895 million were distributed through an equity transaction with DEI.
Subsequent to the GT&S Transaction
Subsequent to the GT&S Transaction, Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Eastern Energy Gas. Eastern Energy Gas made $18 million and $3 million of contributions to the MidAmerican Energy Company Retirement Plan for the years ended December 31, 2021 and 2020, respectively. Eastern Energy Gas made $10 million and $2 million of contributions to the MidAmerican Energy Company Welfare Benefit Plan for the years ended December 31, 2021 and 2020, respectively. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Eastern Energy Gas participates in the BHE GT&S, LLC ("BHE GT&S") defined contribution employee savings plan subsequent to the GT&S Transaction. Eastern Energy Gas' matching contributions are based on each participant's level of contribution. Contributions cannot exceed the maximum allowable for tax purposes. Eastern Energy Gas' contributions to the 401(k) plan were $5 million and $1 million for the years ended December 31, 2021 and 2020, respectively.
Prior to the GT&S Transaction
Defined Benefit Plans
Prior to the GT&S Transaction, certain Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by DEI that provides benefits to multiple DEI subsidiaries. As participating employers, Eastern Energy Gas was subject to DEI's funding policy, which was to contribute annually an amount that is in accordance with the Employee Retirement Income Security Act of 1974. Eastern Energy Gas' net periodic pension credit related to this plan was $(14) million and $(8) million for the years ended December 31, 2020 and 2019, respectively. Net periodic pension (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Operations, except for $(14) million of Eastern Energy Gas' costs for the year ended December 31, 2019 that are recorded in net income from discontinued operations. The funded status of various DEI subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating DEI subsidiaries.
Prior to the GT&S Transaction, certain retiree healthcare and life insurance benefits for Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by DEI that provides certain retiree healthcare and life insurance benefits to multiple DEI subsidiaries. Eastern Energy Gas' net periodic benefit credit related to this plan was $(5) million and $(4) million for the years ended December 31, 2020 and 2019, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Operations, except for less than $(1) million of Eastern Energy Gas' costs for the year ended December 31, 2019 that are recorded in net income from discontinued operations. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating DEI subsidiaries.
Pension benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate pension plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Employee compensation was the basis for allocating pension costs and obligations between EGTS and Hope. Retiree healthcare and life insurance benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate other postretirement benefit plan that provides benefits to both EGTS and Hope. Employee headcount was the basis for allocating other postretirement benefit costs and obligations between EGTS and Hope.
Eastern Energy Gas included the separate pension and other postretirement benefit plans for East Ohio employees covered by collective bargaining units through November 2019, the effective date of the Dominion Energy Gas Restructuring. See Note 3 for more information on the Dominion Energy Gas Restructuring.
Pension Remeasurement
In the third quarter of 2020, Eastern Energy Gas remeasured a pension plan due to a curtailment resulting from the agreement for DEI to retain the assets and obligations of the pension benefit plan associated with the GT&S Transaction. The remeasurement resulted in an increase in the pension benefit obligation of $3 million and a decrease in the fair value of the pension plan assets of $7 million for Eastern Energy Gas. The impact of the remeasurement on net periodic pension benefit credit was recognized prospectively from the remeasurement date and was not material. The discount rate used for the remeasurement was 3.16%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2019.
Voluntary Retirement Program
In March 2019, Eastern Energy Gas announced a voluntary retirement program to employees that met certain age and service requirements. The voluntary retirement program will not compromise safety or Eastern Energy Gas' ability to comply with applicable laws and regulations. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, Eastern Energy Gas recorded a charge of $74 million ($58 million after-tax) included within operations and maintenance expense ($41 million), other income ($1 million) and discontinued operations ($32 million) in the Consolidated Statements of Operations.
In the second quarter of 2019, Eastern Energy Gas remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.10% for the Eastern Energy Gas pension plans and 4.05% for the Eastern Energy Gas other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.
Net Periodic Benefit Credit
Net periodic benefit credit for the plans included the following components for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension | | Other Postretirement |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | | |
Service cost | | $ | 5 | | | $ | 6 | | | $ | 1 | | | $ | 1 | |
Interest cost | | 8 | | | 11 | | | 4 | | | 5 | |
Expected return on plan assets | | (47) | | | (54) | | | (16) | | | (16) | |
Settlement | | — | | | 1 | | | — | | | 1 | |
Net amortization | | 5 | | | 7 | | | (3) | | | (2) | |
Net periodic benefit credit | | $ | (29) | | | $ | (29) | | | $ | (14) | | | $ | (11) | |
Significant assumptions used to determine periodic credits for the years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension | | Other Postretirement |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Discount rate | 3.16% - 3.63% | | 4.10% - 4.42% | | 3.44 | % | | 4.05% - 4.37% |
Expected long-term rate of return on plan assets | 8.60 | % | | 8.65 | % | | 8.50 | % | | 8.50 | % |
Weighted average rate of increase for compensation | 4.73 | % | | 4.55 | % | | N/A | | N/A |
Healthcare cost trend rate | | | | | 6.50 | % | | 6.50 | % |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | | | | | 5.00 | % | | 5.00 | % |
Year that the rate reached the ultimate trend rate | | | | | 2026 | | 2025 |
Defined Contribution Plans
Eastern Energy Gas participated in the DEI defined contribution employee savings plans prior to the GT&S Transaction. Eastern Energy Gas' matching contributions were based on each participant's level of contribution. Contributions could not exceed the maximum allowable for tax purposes. Eastern Energy Gas' contributions to the 401(k) plan were $3 million and $4 million for the years ended December 31, 2020 and 2019, respectively.
(11) Asset Retirement Obligations
Eastern Energy Gas estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Eastern Energy Gas does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on the Cove Point LNG facility, interim removal of natural gas pipelines and certain storage wells in EGTS' underground natural gas storage network cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $73 million and $88 million as of December 31, 2021 and 2020, respectively. Eastern Energy Gas will continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets.
The following table reconciles the beginning and ending balances of Eastern Energy Gas' ARO liabilities for the years ended December 31 (in millions):
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
Beginning balance | $ | 71 | | | $ | 89 | |
Change in estimated costs | — | | | (51) | |
Additions | — | | | 48 | |
Retirements | (17) | | | (3) | |
Disposal of Questar Pipeline Group | — | | | (16) | |
Accretion | 1 | | | 4 | |
Ending balance | $ | 55 | | | $ | 71 | |
| | | |
Reflected as: | | | |
Current liabilities | $ | 33 | | | $ | 36 | |
Other long-term liabilities | 22 | | | 35 | |
Total ARO liability | $ | 55 | | | $ | 71 | |
(12) Risk Management and Hedging Activities
Eastern Energy Gas is exposed to the impact of market fluctuations in commodity prices, interest rates, and foreign currency exchange rates. Eastern Energy Gas is principally exposed to natural gas market fluctuations primarily through fuel retained and used during the operation of the pipeline system as well as lost and unaccounted for gas, to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances, and to foreign currency exchange risk associated with Euro denominated debt. Eastern Energy Gas has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Eastern Energy Gas uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Eastern Energy Gas also uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge its exposure to principal and interest payments denominated in Euros. Eastern Energy Gas does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
Subsequent to the GT&S Transaction, Eastern Energy Gas has elected to offset derivative contracts where master netting arrangements allow. There have been no other significant changes in Eastern Energy Gas' accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | Unit of | | | | |
| | Measure | | 2021 | | 2020 |
| | | | | | |
Interest rate | | U.S. $ | | — | | | 500 | |
Foreign currency | | Euro € | | 250 | | | 250 | |
Natural gas | | Dth | | 2 | | | 5 | |
| | | | | | |
Credit Risk
Eastern Energy Gas is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Eastern Energy Gas' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, Eastern Energy Gas analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Eastern Energy Gas enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, Eastern Energy Gas exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Upon the Cove Point LNG export/liquefaction facility commencing commercial operations, the majority of Cove Point's revenue and earnings are from annual reservation payments under certain terminalling, storage and transportation contracts with ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., LTD., and GAIL Global (USA) LNG, LLC (the "Export Customers"). If such agreements were terminated and Cove Point was unable to replace such agreements on comparable terms, there could be a material impact on results of operations, financial condition and/or cash flows.
The Export Customers comprised approximately 40% and 34% of Eastern Energy Gas' operating revenues for the years ended December 31, 2021 and 2020, respectively, with Eastern Energy Gas' largest customer representing approximately 20% and 17% of such amounts.
For the year ended December 31, 2021, EGTS provided service to 278 customers with approximately 98% of its storage and transportation revenue being provided through firm services. The 10 largest customers provided approximately 38% of the total storage and transportation revenue and the thirty largest provided approximately 71% of the total storage and transportation revenue.
(13) Fair Value Measurements
The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Eastern Energy Gas has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.
The following table presents Eastern Energy Gas' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
As of December 31, 2021 | | | | | | | | |
Assets: | | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | |
| | | | | | | | |
Investment funds | | 13 | | | — | | | — | | | 13 | |
| | $ | 13 | | | $ | 3 | | | $ | — | | | $ | 16 | |
| | | | | | | | |
Liabilities: | | | | | | | | |
| | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | |
| | | | | | | | |
| | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | |
| | | | | | | | |
As of December 31, 2020 | | | | | | | | |
Assets: | | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | 20 | | | $ | — | | | $ | 20 | |
| | | | | | | | |
| | | | | | | | |
| | $ | — | | | $ | 20 | | | $ | — | | | $ | 20 | |
| | | | | | | | |
Liabilities: | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | |
Foreign currency exchange rate derivatives | | — | | | (2) | | | — | | | (2) | |
Interest rate derivatives | | — | | | (6) | | | — | | | (6) | |
| | $ | — | | | $ | (9) | | | $ | — | | | $ | (9) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Eastern Energy Gas bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of Eastern Energy Gas' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Eastern Energy Gas' variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt as of December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 3,906 | | | $ | 4,266 | | | $ | 4,425 | | | $ | 5,012 | |
(14) Commitments and Contingencies
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Eastern Energy Gas' current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
Air
Revisions to Ozone National Ambient Air Quality Ozone Standards
The Clean Air Act includes National Ambient Air Quality Standards ("NAAQS"). States adopt rules that ensure their air quality meets the NAAQS. In October 2015, the United States Environmental Protection Agency ("EPA") published a rule lowering the ground level ozone NAAQS for non-attainment designations. States had until August 2021 to develop plans to address the new standard, which did not result in a material impact on Eastern Energy Gas' results of operations and cash flows. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to Eastern Energy Gas, the EPA must, by April 30, 2022, approve or disapprove the interstate ozone state implementation plans of Maryland, New York, Ohio, Pennsylvania and West Virginia. Also in January 2022, the EPA initiated interagency review of a new rule to address "good neighbor" state implementation plan provisions. While the interagency review is not yet complete and the proposed rule is not available for public comment, the EPA has indicated that the action would apply in certain states for which the EPA has either disapproved a "good neighbor" state implementation plan submission or has made a finding of failure to submit such a plan for the 2015 ozone NAAQS. The action would determine whether and to what extent ozone-precursor emissions reductions are required to eliminate significant contribution or interference with maintenance from upwind states that are linked to air quality problems in other states for the 2015 standard. Until the EPA takes final action consistent with this decree, Eastern Energy Gas cannot predict the impact to its results of operations, financial condition and/or cash flows.
Oil and Gas New Source Performance Standards
In August 2020, the EPA issued two final amendments related to the reconsideration of the New Source Performance Standard ("NSPS") for the oil and natural gas sector applicable to volatile organic compound and methane emissions. Together, the two amendments have the effect of rescinding the methane portion of the NSPS for all segments of the oil and natural gas sector, rescinding all NSPS for the transmission and storage segment and modifying some of the NSPS volatile organic compound requirements for facilities in the production and processing segments. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution reinstated the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA proposed rules that would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposals would expand and strengthen emissions reduction requirements for new, modified and reconstructed oil and natural gas sources and would require states to reduce methane emissions from existing sources nationwide. The EPA took comment on the proposed rules through January 31, 2022. The EPA intends to issue a supplemental proposal in 2022, including draft regulatory text, and plans to finalize the rules by the end of 2022. Until the EPA ultimately takes final action on this rulemaking, Eastern Energy Gas cannot predict the impact to its results of operations, financial condition and/or cash flows.
Carbon Regulations
In August 2016, the EPA issued a draft rule proposing to reaffirm that a source's obligation to obtain a prevention of significant deterioration or Title V permit for greenhouse gases ("GHG") is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of carbon dioxide equivalent emissions under which a source would not be required to apply best available control technology for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, Eastern Energy Gas cannot predict the impact to its results of operations, financial condition and/or cash flows.
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Surety Bonds
As of December 31, 2021, Eastern Energy Gas had purchased $19 million of surety bonds. Under the terms of surety bonds, Eastern Energy Gas is obligated to indemnify the respective surety bond company for any amounts paid.
(15) Revenue from Contracts with Customers
The following table summarizes Eastern Energy Gas' Customer Revenue by regulated and nonregulated, with further disaggregation of regulated by line of business, for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Customer Revenue: | | | | | |
Regulated: | | | | | |
Gas transportation and storage | $ | 1,044 | | | $ | 1,242 | | | $ | 1,300 | |
Wholesale | 57 | | | 43 | | | 9 | |
Other | (2) | | | 4 | | | 7 | |
Total regulated | 1,099 | | | 1,289 | | | 1,316 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Nonregulated | 767 | | | 798 | | | 849 | |
Total Customer Revenue | 1,866 | | | 2,087 | | | 2,165 | |
Other revenue | 4 | | | 3 | | | 4 | |
Total operating revenue | $ | 1,870 | | | $ | 2,090 | | | $ | 2,169 | |
Remaining Performance Obligations
The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
Eastern Energy Gas | $ | 1,594 | | | $ | 16,126 | | | $ | 17,720 | |
(16) Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Unrecognized | | | | | | Unrealized | | | | Accumulated |
| | Amounts On | | | | | | Losses On | | | | Other |
| | Retirement | | | | | | Cash Flow | | Noncontrolling | | Comprehensive |
| | Benefits | | | | | | Hedges | | Interests | | Loss |
Balance, December 31, 2018 | | $ | (144) | | | | | | | $ | (25) | | | $ | — | | | $ | (169) | |
| | | | | | | | | | | | |
Other comprehensive income (loss) | | 38 | | | | | | | (56) | | | — | | | (18) | |
Balance, December 31, 2019 | | (106) | | | | | | | (81) | | | — | | | (187) | |
Other comprehensive income | | 94 | | | | | | | 30 | | | 10 | | | 134 | |
Balance, December 31, 2020 | | (12) | | | | | | | (51) | | | 10 | | | (53) | |
Other comprehensive income (loss) | | 6 | | | | | | | 9 | | | (5) | | | 10 | |
Balance, December 31, 2021 | | $ | (6) | | | | | | | $ | (42) | | | $ | 5 | | | $ | (43) | |
| | | | | | | | | | | | |
The following table shows the reclassifications from AOCI to net income for the year ended December 31 (in millions):
| | | | | | | | | | | | | | |
| | | | Affected Line |
| | | | Item In The |
| | Amounts | | Consolidated |
| | Reclassified | | Statements of |
| | From AOCI | | Operations |
2021 | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | |
| | | | |
Interest rate contracts | | $ | 6 | | | Interest expense |
Foreign currency contracts | | 21 | | | Other, net |
Total | | 27 | | | |
Tax | | (7) | | | Income tax expense (benefit) |
Total, net of tax | | $ | 20 | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
2020 | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | |
| | | | |
Interest rate contracts | | $ | 157 | | | Interest expense |
Foreign currency contracts | | (25) | | | Other, net |
Total | | 132 | | | |
Tax | | (34) | | | Income tax expense (benefit) |
Total, net of tax | | $ | 98 | | | |
Unrecognized pension costs: | | | | |
Actuarial losses | | $ | 6 | | | Other, net |
Total | | 6 | | | |
Tax | | (2) | | | Income tax expense (benefit) |
Total, net of tax | | $ | 4 | | | |
| | | | |
2019 | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | |
Commodity contracts | | $ | (4) | | | Net income from discontinued operations |
Interest rate contracts | | 5 | | | Interest expense |
Foreign currency contracts | | 6 | | | Other, net |
Total | | 7 | | | |
Tax | | (2) | | | Income tax expense (benefit) |
Total, net of tax | | $ | 5 | | | |
Unrecognized pension costs: | | | | |
Actuarial losses | | $ | 7 | | | Other, net |
Total | | 7 | | | |
Tax | | (2) | | | Income tax expense (benefit) |
Total, net of tax | | $ | 5 | | | |
The following table presents selected information related to losses on cash flow hedges included in AOCI in Eastern Energy Gas' Consolidated Balance Sheet as of December 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | AOCI After-Tax | | Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | | Maximum Term |
| | | | | | |
Interest rate | | $ | (38) | | | $ | (4) | | | 276 months |
Foreign currency | | (4) | | | (3) | | | 54 months |
Total | | $ | (42) | | | $ | (7) | | | |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates and foreign currency exchange rates.
In July 2020, Eastern Energy Gas recorded a loss of $141 million ($105 million after-tax) in interest expense in the Consolidated Statement of Operations, for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction. The derivatives related to these hedges were settled in October 2020 for a cash payment of $165 million.
(17) Variable Interest Entities
The primary beneficiary of a variable interest entity ("VIE") is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As part of the Dominion Energy Gas Restructuring, DEI contributed to Eastern Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, DEI sold its retained 25% noncontrolling limited partner interest in Cove Point. As discussed in Note 3, as part of the GT&S Transaction, Eastern Energy Gas finalized a restructuring which included the disposition of a 50% noncontrolling interest in Cove Point to DEI, which resulted in Eastern Energy Gas owning 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $12 million, $12 million and $16 million for the years ended December 31, 2021, 2020 and 2019, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $7 million and $22 million as of December 31, 2021 and 2020 respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities is the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provides marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of Carolina Gas Services costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an affiliated VIE, of $23 million and $33 million for the years ended December 31, 2020 and 2019, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DEQPS provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DEQPS costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Services, Inc. ("DES"), an affiliated VIE, of $90 million and $119 million for the years ended December 31, 2020 and 2019, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DES as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DES provided accounting, legal, finance and certain administrative and technical services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DES costs.
(18) Noncontrolling Interests
Included in noncontrolling interests in the Consolidated Financial Statements are DEI's 50% interest in Cove Point (effective November 2020), Brookfield's 25% interest in Cove Point (effective December 2019) and the public's ownership interest in Northeast Midstream (through January 2019).
Noncontrolling Interest in Northeast Midstream
Northeast Midstream was a publicly traded master limited partnership that included common units, subordinated units, Series A Preferred Units and incentive distribution rights as its participating securities. In accordance with the partnership agreement, when the subordination period ended, all subordinated units converted into common units on a 1-for-one basis and participated pro rata with the other common units in distributions.
In January 2019, DEI and Northeast Midstream closed on an agreement and plan of merger pursuant to which DEI acquired each outstanding common unit representing limited partner interests in Northeast Midstream not already owned by DEI through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Northeast Midstream was converted into the right to receive 0.2492 shares of DEI common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Northeast Midstream was converted into common units representing limited partner interests in Northeast Midstream in accordance with the terms of Northeast Midstream's partnership agreement. The merger was accounted for by DEI following the guidance for a change in a parent company's ownership interest in a consolidated subsidiary. Because DEI controlled Northeast Midstream both before and after the merger, the changes in DEI's ownership interest in Northeast Midstream were accounted for as an equity transaction and no gain or loss was recognized. In connection with the merger, DEI recognized $40 million of income taxes in equity primarily attributable to establishing additional regulatory liabilities related to excess deferred income taxes and changes in state income taxes.
Subsequent to this activity, as a result of the Dominion Energy Gas Restructuring, Eastern Energy Gas is considered to have acquired all of the outstanding partnership interests of Northeast Midstream and Northeast Midstream became a wholly-owned subsidiary of Eastern Energy Gas.
(19) Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| December 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 22 | | | $ | 35 | |
Restricted cash and cash equivalents | 17 | | | 13 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 39 | | | $ | 48 | |
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Supplemental disclosure of cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 144 | | | $ | 317 | | | $ | 291 | |
Income taxes (received) paid, net | $ | (60) | | | $ | 31 | | | $ | 65 | |
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accruals related to property, plant and equipment additions | $ | 42 | | | $ | 30 | | | $ | 25 | |
Equity distributions | $ | (137) | | | $ | — | | | $ | — | |
Equity contributions | $ | 73 | | | $ | — | | | $ | — | |
Distribution of Questar Pipeline Group | $ | — | | | $ | (699) | | | $ | — | |
Distribution of 50% interest in Cove Point | $ | — | | | $ | (2,765) | | | $ | — | |
Acquisition of Eastern Energy Gas by BHE | $ | — | | | $ | 343 | | | $ | — | |
| | | | | |
(20) Related Party Transactions
Transactions Prior to the GT&S Transaction
Prior to the GT&S Transaction, Eastern Energy Gas engaged in related party transactions primarily with other DEI subsidiaries (affiliates). Eastern Energy Gas' receivable and payable balances with affiliates were settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing date of the GT&S Transaction.
Eastern Energy Gas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also entered into certain other contracts with affiliates, and related parties, including construction services, which were presented separately from contracts involving commodities or services. See Note 3 for information regarding the Dominion Energy Gas Restructuring, an affiliated transaction. Eastern Energy Gas participated in certain DEI benefit plans as described in Note 10.
DES, Carolina Gas Services, DEQPS and other affiliates provided accounting, legal, finance and certain administrative and technical services to Eastern Energy Gas. Eastern Energy Gas provided certain services to related parties, including technical services.
The financial statements for the years ended December 31, 2020 and 2019 include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to Eastern Energy Gas on the basis of direct and allocated methods in accordance with Eastern Energy Gas' services agreements with DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs were allocated based on the proportional level of effort devoted by DES, Carolina Gas Services and DEQPS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Subsequent to the GT&S Transaction, and with the exception of Cove Point, Eastern Energy Gas' transactions with other DEI subsidiaries are no longer related party transactions.
Presented below are Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliated and related parties for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | 2020 | | 2019 |
Sales of natural gas and transportation and storage services | | | $ | 207 | | | $ | 249 | |
Purchases of natural gas and transportation and storage services | | | 10 | | | 12 | |
Services provided by related parties(1) | | | 129 | | | 226 | |
Services provided to related parties(2) | | | 83 | | | 164 | |
(1)Includes capitalized expenditures of $14 million and $19 million for the years ended December 31, 2020 and 2019, respectively.
(2)Includes amounts attributable to Atlantic Coast Pipeline, a related party VIE prior to the GT&S Transaction. See below for more information.
EGTS provided services to Atlantic Coast Pipeline, which totaled $46 million and $103 million for the years ended December 31, 2020 and 2019, respectively, included in operating revenue in the Consolidated Statements of Operations.
Interest income related to the affiliated notes receivable under the DEI money pool was $3 million for the year ended December 31, 2020.
Interest income on affiliated notes receivable from East Ohio and EGP borrowings under intercompany revolving credit agreements with Eastern Energy Gas was $14 million for the year ended December 31, 2019.
Interest income related to DEI's loan and promissory note associated with Cove Point's term loan was $82 million for the year ended December 31, 2019. In September 2019, DEI repaid the promissory note to Cove Point and the proceeds were used by Cove Point to repay its $3.0 billion term loan.
Eastern Energy Gas' affiliated notes receivable from DEI totaled $1.8 billion as of December 31, 2019. In August 2020, DEI repaid the remaining principal balance outstanding. Interest income on the promissory notes was $32 million and $5 million for the years ended December 31, 2020 and 2019, respectively.
As of December 31, 2019, Eastern Energy Gas' affiliated notes receivable from East Ohio totaled $1.7 billion. In June 2020, East Ohio repaid the remaining principal balance outstanding. Interest income on these promissory notes was $33 million and $72 million for the years ended December 31, 2020 and 2019, respectively.
Interest charges related to Eastern Energy Gas' total borrowings under an intercompany revolving credit agreement with DEI were $3 million for each of the years ended December 31, 2020 and 2019.
Interest charges related to DCP's total borrowings from DEI totaled $94 million for the year ended December 31, 2019.
Interest charges related to DCP's total borrowings from DES were $3 million for each of the years ended December 31, 2020 and 2019.
Interest charges related to Northeast Midstream's promissory note with DEI were $10 million for the year ended December 31, 2019.
For the years ended December 31, 2020 and 2019, Eastern Energy Gas, including entities acquired in the Dominion Energy Gas Restructuring, distributed $4.3 billion and $603 million to DEI, respectively.
Transactions Subsequent to the GT&S Transaction
Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $8 million and $20 million as of December 31, 2021 and 2020, respectively. Eastern Energy Gas received net cash receipts for federal and state income taxes from BHE totaling $47 million and $76 million for the years ended December 31, 2021 and 2020, respectively.
Other assets included amounts due from an affiliate of $3 million and $7 million as of December 31, 2021 and 2020, respectively.
As of December 31, 2021, Eastern Energy Gas had $5 million of natural gas imbalances payable to affiliates, presented in other current liabilities on the Consolidated Balance Sheet.
Presented below are Eastern Energy Gas' significant transactions with affiliated and related parties for the years ended December 31 (in millions):
| | | | | | | | | | | | | | | | | |
| | | 2021 | | 2020 |
Sales of natural gas and transportation and storage services | | | $ | 32 | | | $ | 4 | |
Purchases of natural gas and transportation and storage services | | | 5 | | | — | |
Services provided by related parties | | | 51 | | | 4 | |
Services provided to related parties | | | 32 | | | 7 | |
Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, expiring in November 2022. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of December 31, 2020, $9 million was outstanding under the credit agreement with a weighted average interest rate of 0.55%. There were no amounts outstanding under the credit agreement as of December 31, 2021.
BHE GT&S has an intercompany revolving credit agreement from Eastern Energy Gas expiring in December 2022. In March 2021, BHE GT&S increased its credit facility limit from $200 million to $400 million. The credit agreement has a variable interest rate based on LIBOR plus a fixed spread. As of December 31, 2021 and 2020, $8 million and $124 million, respectively, was outstanding under the credit agreement.
Eastern Energy Gas participates in certain MidAmerican Energy benefit plans as described in Note 10. As of December 31, 2021 and 2020, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $95 million and $115 million, respectively.
Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
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Item 9A. | Controls and Procedures |
Item 9A.Controls and Procedures
Disclosure Controls and Procedures
At the end of the period covered by this Annual Report on Form 10-K, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, and Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC'sUnited States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended December 31, 20182021 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
Management of each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, and Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC, respectively, is responsible for establishing and maintaining, for such entity, adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Under the supervision and with the participation of management for each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, such management conducted an evaluation for the relevant entity of the effectiveness of internal control over financial reporting as of December 31, 2018,2021, as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, management for each such respective entity used the criteria set forth in the framework in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in "Internal Control - Integrated Framework (2013)," management for each such respective entity concluded that internal control over financial reporting for such entity was effective as of December 31, 2018.2021.
| | | | | | | | | | | | | | |
Berkshire Hathaway Energy Company | | PacifiCorp | | MidAmerican Funding, LLC |
February 25, 2022 | | February 25, 2022 | | February 25, 2022 |
| | | | |
Berkshire Hathaway Energy Company | | PacifiCorp | | MidAmerican Funding, LLC |
February 22, 2019 | | February 22, 2019 | | February 22, 2019 |
| | | | |
MidAmerican Energy Company | | Nevada Power Company | | Sierra Pacific Power Company |
February 22, 201925, 2022 | | February 22, 201925, 2022 | | February 22, 201925, 2022 |
| | | | |
Item 9B.Eastern Energy Gas Holdings, LLC | Other Information | | | |
February 25, 2022 | | | | |
Item 9B.Other Information
None.
PART III
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Item 10. | Directors, Executive Officers and Corporate Governance |
Item 10.Directors, Executive Officers and Corporate Governance
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, AND SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
PacifiCorp is an indirect subsidiary of BHE, and its directors consist of executive management from both BHE and PacifiCorp. Each director was elected based on individual responsibilities, experience in the energy industry and functional expertise. There are no family relationships among the executive officers, nor any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of February 21, 2019,January 31, 2022, with respect to the current directors and executive officers of PacifiCorp:
WILLIAM J. FEHRMAN, 58, Chairman61, Chair of the Board of Directors and Chief Executive Officer since January 2018. Mr. Fehrman has also been President, Chief Executive Officer and directorDirector of BHE since January 2018. Mr. Fehrman was Chief Executive Officer of MidAmerican Energy Company from 2008 to January 2018 and President and directorDirector from 2007 to January 2018. Mr. Fehrman joined BHE in 2006 and has extensive executive management experience in the energy industry with strong regulatory and operational skills.
STEFAN A. BIRD, 52,55, Director since 2015. President and Chief Executive Officer of Pacific Power and director since 2015. Mr. Bird was Senior Vice President, Commercial and Trading, of PacifiCorp from 2007 to 2014. Mr. Bird joined BHE in 1998 and has significant operational, public policy and leadership experience in the energy industry, including expertise in energy supply management, resource acquisition and federal and state regulatory matters.
GARY W. HOOGEVEEN, 50,53, Director since November 2018, President since June 2018 and Chief Executive Officer since November 2018 of Rocky Mountain Power since November 2018.Power. Prior to his current positionpositions, Mr. Hoogeveen served as Senior Vice President and Chief Commercial Officer of Rocky Mountain Power since November 2014 and President and CEO of Kern River Gas Transmission Company from 2010 to 2014. He joined Kern River after serving as Vice President of Customer Service and Business Development for Northern Natural Gas Company. Prior to joining Northern Natural Gas heCompany, Mr. Hoogeveen held various management positions at Berkshire Hathaway Energy.Energy, joining BHE in 2000. He has significant operational, public policy and leadership experience in both the electricity and natural gas industries, including customer, regulatory and government relations.
NIKKI L. KOBLIHA, 46,49, Director since 2017. Vice President and Chief Financial Officer since 2015 and Treasurer and director since 2017. Ms. Kobliha joined PacifiCorp in 1997 and has significant financial, accounting and leadership experience in the energy industry, including expertise in financial reporting to the SEC and FERC.
PATRICK J. GOODMANCALVIN D. HAACK, 52,53, Director since 2006.May 2020. Mr. GoodmanHaack has been ExecutiveSenior Vice President and Chief Financial Officer of BHE since 2012March 2020 and was Senior Vice President and Chief Financial OfficerTreasurer of BHE from 19992010 to 2012.2020. Mr. GoodmanHaack joined BHE in 19951997 and has significant financial experience, including expertise in mergers and acquisitions, accounting, treasury and tax functions. Mr. GoodmanHaack is also a manager of MidAmerican Funding, LLC and Eastern Energy Gas Holdings, LLC.
NATALIE L. HOCKEN, 49,52, Director since 2007. Ms. Hocken has been Senior Vice President and General Counsel of BHE since 2015 and Corporate Secretary since 2017. Ms. Hocken was Senior Vice President, Transmission and System Operations of PacifiCorp from 2012 to 2015 and Vice President and General Counsel of Pacific Power from 2007 to 2012. Ms. Hocken joined PacifiCorp in 2002 and has significant experience in the utility industry, including expertise in transmission, legal matters and federal and state regulatory matters. Ms. Hocken is also a manager of MidAmerican Funding, LLC and Eastern Energy Gas Holdings, LLC.
Board's Role in the Risk Oversight Process
PacifiCorp's Board of Directors is comprised of a combination of BHE senior executives and PacifiCorp senior management who have direct and indirect responsibility for the management and oversight of risk. PacifiCorp's Board of Directors has not established a separate risk management and oversight committee.
Audit Committee and Audit Committee Financial Expert
During the year ended December 31, 2018,2021, and as of the date of this Annual Report on Form 10-K, PacifiCorp's Board of Directors did not have an audit committee. PacifiCorp is not required to have an audit committee as its common stock is indirectly and wholly owned by BHE. However, the audit committee of BHE acts as the audit committee for PacifiCorp.
Code of Ethics
PacifiCorp has adopted a code of ethics that applies to its principal executive officer, its principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is incorporated by reference in the exhibits to this Annual Report on Form 10-K.
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Item 11. | Executive Compensation |
Item 11.Executive Compensation
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, AND SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Compensation Discussion and Analysis
Compensation Philosophy and Overall Objectives
On January 10, 2018, Mr. Gregory E. Abel resigned as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer and Mr. William J. Fehrman was elected as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer. Mr. William J. Fehrman, PacifiCorp's ChairmanChair of the Board of Directors and Chief Executive Officer, or ChairmanChair and CEO, received no direct compensation from PacifiCorp. PacifiCorp reimbursed its indirect parent company, BHE, for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries.
PacifiCorp believes that the compensation paid to each of its Chief Financial Officer, or CFO, and its other most highly compensated executive officers, to whom PacifiCorp refers collectively as its Named Executive Officers, or NEOs, should be closely aligned with its overall performance, and each NEO's contribution to that performance, on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for the organization. PacifiCorp's compensation programs are designed to provide its NEOs meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and non-financial objectives, among which are customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, which PacifiCorp believes contribute to its long-term success.
How Compensation is Compensation Determined
PacifiCorp's compensation committee consists solely of the ChairmanChair and CEO. On January 10, 2018, Mr. Fehrman replaced Mr. Abel as the sole member of PacifiCorp's compensation committee. Mr. Fehrman also serves as BHE's President and Chief Executive Officer. The ChairmanChair and CEO is responsible for the establishment and oversight of PacifiCorp's compensation policy and for approving compensation decisions for its NEOs, such as approving base pay increases, incentive and performance awards, off-cycle pay changes, and participation in other employee benefit plans and programs.
PacifiCorp's criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. PacifiCorp does not specifically use other companies as benchmarks when establishing its NEOs' compensation.
Discussion and Analysis of Specific Compensation Elements
Base Salary
PacifiCorp determines base salaries for all of its NEOs, other than the ChairmanChair and CEO, by reviewing its overall performance, and each NEO's performance, the value each NEO brings to PacifiCorp and general labor market conditions. Base salary is intended to compensate NEOs for services rendered during the fiscal year and to provide sufficient cash income for retention and recruitment purposes. While base salary provides a base level of compensation intended to be competitive with the external market, the annual base salary adjustment for each NEO, other than the ChairmanChair and CEO, is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. All merit increases are approved by the ChairmanChair and CEO and take effect in the last payroll period of the year. An increase or decrease in base salary may also result from a promotion or other significant change in aan NEO's responsibilities during the year. For 2018,2021, base salaries for all NEOs, other than the ChairmanChair and CEO, increased on average by 2.45%1.39% effective December 26, 2017,2020, reflecting merit increases.
Short-Term Incentive Compensation
The objective of short-term incentive compensation is to reward the achievement of significant annual corporate and business unit goals while also providing NEOs with competitive total cash compensation.
Annual Incentive Plan
Under PacifiCorp's Annual Incentive Plan, or AIP, all NEOs, other than the ChairmanChair and CEO, are eligible to earn an annual discretionary cash incentive award, which is determined on a subjective basis at the ChairmanChair and CEO's sole discretion and is not based on a specific formula or cap. The ChairmanChair and CEO considers a variety of factors in determining each NEO's annual incentive award including the NEO's performance, PacifiCorp's overall performance and each NEO's contribution to that overall performance. The ChairmanChair and CEO evaluates performance using financial and non-financial objectives, including customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, as well as the NEO's response to issues and opportunities that arise during the year. No factor was individually material to the ChairmanChair and CEO's determination regarding the amounts paid to each NEO under the AIP for 2018.2021. Approved awards are paid prior to year-end.
Performance Awards
In addition to the annual awards under the AIP, PacifiCorp may grant cash performance awards periodically during the year to one or more NEOs, other than the ChairmanChair and CEO, to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and are approved by the ChairmanChair and CEO. In 2018,2021, a cash performance award was granted to Ms. Kobliha in recognition of her outstanding efforts.
Long-Term Incentive Compensation
The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. PacifiCorp's current long-term incentive compensation program is cash-based. PacifiCorp does not utilize stock options or other forms of equity-based awards.
Long-Term Incentive Partnership Plan
The PacifiCorp Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align PacifiCorp's interests and the interests of the participating employees. All of PacifiCorp's NEOs, other than the ChairmanChair and CEO, participate in the LTIP. The LTIP provides for annual discretionary awards based upon significant accomplishments by the individual participants and the achievement of the financial and non-financial objectives previously described. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated by January of each plan year. The BHE ChairmanChair and PacifiCorp's Presidents approve eligibility to participate in the LTIP and the amount of the incentive award. Awards are capped at 1.0 times base salary and finalized in the first quarter of the following year. The BHE Chairman and PacifiCorp's Presidents may grant a supplemental award to any participant for the award year separate from the incentive award, subject to the same terms and conditions as the incentive award. PacifiCorp's Presidents may participate in the LTIP but only the BHE ChairmanChair shall make determinations regarding their participation and the value of their incentive award. These cash-based awards are subject to mandatory deferral and equal annual vesting over a four-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives. Gains or losses may be incurred based on investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the four-year mandatory deferral and vesting period. Vested balances (including any investment gains or losses thereon) of terminating participants are paid at the time of termination.
Deferred Compensation Plan
PacifiCorp's Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs, other than the ChairmanChair and CEO, to make voluntary deferrals of up to 50% of base salary and 100% of short-term incentive compensation awards. PacifiCorp includes the DCP as part of the participating NEO's overall compensation in order to provide a comprehensive, competitive package. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered under the DCP and selected by the participant. The plan allows participants to choose from three forms of distribution. The plan permits PacifiCorp to make discretionary contributions on behalf of participants.
Potential Payments Upon Termination
PacifiCorp's NEOs other than the Chairman and CEO, are generally not entitled to severance or enhanced benefits upon termination of employment or change in control. However,None of PacifiCorp's NEOs have an employment agreement; therefore, payments upon any termination ofare determined by the applicable plan documents and our general employment PacifiCorp's other NEOs would be entitled to the vested balances in the LTIP, DCPpolicies and PacifiCorp's non-contributory defined benefit pension plan, or the Retirement Plan.practices as discussed below.
Compensation Committee Report
Mr. Fehrman, PacifiCorp's current ChairmanChair and CEO and sole member of PacifiCorp's compensation committee, has reviewed the Compensation Discussion and Analysis and, based on this review, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
William J. Fehrman
Summary Compensation Table
The following table sets forth information regarding compensation earned by each of PacifiCorp's NEOs during the years indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Change in | | | | |
| | | | | | | | Pension | | | | |
| | | | | | | | Value and | | | | |
| | | | | | | | Nonqualified | | | | |
| | | | | | | | Deferred | | | | |
| | | | | | | | Compensation | | All Other | | |
Name and Principal Position | | Year | | Salary | | Bonus (1) | | Earnings(2) | | Compensation (3) | | Total (4) |
| | | | | | | | | | | | |
William J. Fehrman(5) | | 2021 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Chair of the Board of Directors | | 2020 | | — | | | — | | | — | | | — | | | — | |
and Chief Executive Officer | | 2019 | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | |
Stefan A. Bird | | 2021 | | 473,011 | | | 1,142,660 | | | — | | | 33,010 | | | 1,648,681 | |
President and Chief Executive | | 2020 | | 375,000 | | | 1,327,839 | | | 17,723 | | | 33,479 | | | 1,754,041 | |
Officer, Pacific Power | | 2019 | | 365,000 | | | 1,286,958 | | | 10,152 | | | 31,845 | | | 1,693,955 | |
| | | | | | | | | | | | |
Gary W. Hoogeveen | | 2021 | | 473,011 | | | 1,066,924 | | | — | | | 33,010 | | | 1,572,945 | |
President and Chief Executive | | 2020 | | 361,080 | | | 1,109,713 | | | — | | | 32,690 | | | 1,503,483 | |
Officer, Rocky Mountain Power | | 2019 | | 350,000 | | | 964,837 | | | — | | | 32,731 | | | 1,347,568 | |
| | | | | | | | | | | | |
Nikki L. Kobliha | | 2021 | | 262,260 | | | 396,880 | | | — | | | 32,651 | | | 691,791 | |
Vice President, Chief Financial | | 2020 | | 262,260 | | | 330,510 | | | 37,438 | | | 32,286 | | | 662,494 | |
Officer and Treasurer | | 2019 | | 239,571 | | | 243,289 | | | 33,825 | | | 31,391 | | | 548,076 | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Change in | | | | |
| | | | | | | | Pension | | | | |
| | | | | | | | Value and | | | | |
| | | | | | | | Nonqualified | | | | |
| | | | | | | | Deferred | | | | |
| | | | | | | | Compensation | | All Other | | |
Name and Principal Position | | Year | | Base Salary | | Bonus (1) | | Earnings(2) | | Compensation (3) | | Total (4) |
| | | | | | | | | | | | |
William J. Fehrman(6)(7) | | 2018 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | — |
|
Chairman of the Board of Directors | | 2017 | | — |
| | — |
| | — |
| | — |
| | — |
|
and Chief Executive Officer | | 2016 | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | |
Gregory E. Abel (5)(6) | | 2018 | | — |
| | — |
| | — |
| | — |
| | — |
|
Chairman of the Board of Directors | | 2017 | | — |
| | — |
| | — |
| | — |
| | — |
|
and Chief Executive Officer | | 2016 | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | |
Stefan A. Bird | | 2018 | | 355,000 |
| | 1,058,696 |
| | 29,549 |
| | 31,633 |
| | 1,474,878 |
|
President and Chief Executive | | 2017 | | 346,000 |
| | 1,116,105 |
| | 9,480 |
| | 30,965 |
| | 1,502,550 |
|
Officer, Pacific Power | | 2016 | | 338,000 |
| | 738,784 |
| | 629 |
| | 13,958 |
| | 1,091,371 |
|
| | | | | | | | | | | | |
Cindy A. Crane(8) | | 2018 | | 355,000 |
| | 683,123 |
| | — |
| | 32,873 |
| | 1,070,996 |
|
President and Chief Executive | | 2017 | | 346,000 |
| | 1,252,241 |
| | 45,016 |
| | 31,938 |
| | 1,675,195 |
|
Officer, Rocky Mountain Power | | 2016 | | 338,000 |
| | 758,248 |
| | 35,752 |
| | 15,841 |
| | 1,147,841 |
|
| | | | | | | | | | | | |
Gary W. Hoogeveen(8) | | 2018 | | 315,570 |
| | 898,733 |
| | — |
| | 32,484 |
| | 1,246,787 |
|
President and Chief Executive | | 2017 | | — |
| | — |
| | — |
| | — |
| | — |
|
Officer, Rocky Mountain Power | | 2016 | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | |
Nikki L. Kobliha | | 2018 | | 224,510 |
| | 190,045 |
| | — |
| | 30,804 |
| | 445,359 |
|
Vice President, Chief Financial | | 2017 | | 217,079 |
| | 122,400 |
| | 18,304 |
| | 30,415 |
| | 388,198 |
|
Officer and Treasurer | | 2016 | | 203,900 |
| | 143,004 |
| | 9,728 |
| | 29,585 |
| | 386,217 |
|
| |
(1) | Consists of annual cash incentive awards earned pursuant to the AIP for PacifiCorp's NEOs, performance awards for Ms. Kobliha in recognition of efforts to support PacifiCorp's objectives and the vesting of LTIP awards and associated vested earnings. The breakout for 2018 is as follows: |
(1)Consists of annual cash incentive awards earned pursuant to the AIP for PacifiCorp's NEOs, performance awards, and the vesting of LTIP awards and associated vested earnings. The breakout for 2021 is as follows: | | | | | | | | LTIP | | LTIP |
| | | | Performance | | Vested | | Vested | | | | Performance | | Vested | | Vested | |
| | AIP | | Award | | Awards | | Earnings | | Total | | AIP | | Award | | Awards | | Earnings | | Total |
Stefan A. Bird | | $ | 532,500 |
| | $ | — |
| | $ | 591,250 |
| | $ | (65,054 | ) | | $ | 526,196 |
| Stefan A. Bird | | $ | 400,000 | | | $ | — | | | $ | 685,250 | | | $ | 57,410 | | | $ | 742,660 | |
Cindy A. Crane | | — |
| | — |
| | 741,625 |
| | (58,502 | ) | | 683,123 |
| |
Gary W. Hoogeveen | | 406,250 |
| | — |
| | 532,160 |
| | (39,677 | ) | | 492,483 |
| Gary W. Hoogeveen | | 400,000 | | | — | | | 467,000 | | | 199,924 | | | 666,924 | |
Nikki L. Kobliha | | 90,478 |
| | 25,000 |
| | 81,625 |
| | (7,058 | ) | | 74,567 |
| Nikki L. Kobliha | | 96,512 | | | 40,000 | | | 157,125 | | | 103,243 | | | 260,368 | |
The ultimate payouts of LTIP awards are undeterminable as the amounts to be paid out may increase or decrease depending on investment performance. BHE's ChairmanChair and PacifiCorp's Presidents establish the award categories for determining LTIP awards based on net income target goals or other criteria. In 2018,2021, the gross award was subjectively determined at the discretion of the BHE ChairmanChair and PacifiCorpPacifiCorp's Presidents based on the overall achievement of PacifiCorp's financial and non-financial objectives including customer service, employee commitment and safety, environmental respect, regulatory integrity, operational excellence and financial strength.
| |
(2) | Amounts are based upon the aggregate increase in the actuarial present value of all qualified and nonqualified defined benefit plans, which includes the Retirement Plan. Refer to the Pension Benefits table below for a discussion of the assumptions used in calculating these amounts. No participant in PacifiCorp's nonqualified deferred compensation plans earned "above market" or "preferential" earnings on amounts deferred. Negative amounts for the change in pension value not reported in the Summary Compensation Table are as follows: Ms. Crane $(9,651), and Ms. Kobliha $(11,646). |
(2)Amounts are based upon the aggregate change in the actuarial present value of all qualified and nonqualified defined benefit plans, which includes the Retirement Plan. For Mr. Bird and Ms. Kobliha, such change was negative ($(10,705) and $(14,812), respectively. Refer to the Pension Benefits table below for a discussion of the assumptions used in calculating these amounts. No participant in PacifiCorp's nonqualified deferred compensation plans earned "above market" or "preferential" earnings on amounts deferred.
| |
(3) | Amounts consist of PacifiCorp K Plus Employee Savings Plan, or 401(k) Plan, contributions PacifiCorp paid on behalf of the NEOs, except for Mr. Bird, Ms. Crane and Mr. Hoogeveen for whom PacifiCorp also includes an amount paid to each of them as a tax gross-up with respect to a personal benefit with a value less than $10,000. |
| |
(4) | Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the Summary Compensation Table. |
| |
(5) | Mr. Abel received no direct compensation from PacifiCorp. PacifiCorp reimburses BHE for the cost of Mr. Abel's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. In 2018, PacifiCorp reimbursed BHE $0 for the cost of Mr. Abel's time spent on matters supporting PacifiCorp pursuant to the intercompany administrative services agreement. |
| |
(6) | On January 10, 2018, Mr. Gregory E. Abel resigned as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer and Mr. William J. Fehrman was elected as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer. |
| |
(7) | Mr. Fehrman receives no direct compensation from PacifiCorp. PacifiCorp reimburses BHE for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. In 2018, PacifiCorp reimbursed BHE $215,435 for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp pursuant to the intercompany administrative services agreement. |
| |
(8) | On June 1, 2018, Gary W. Hoogeveen succeeded Cindy A. Crane as Rocky Mountain Power's president. On November 28, 2018, Gary W. Hoogeveen also succeeded Cindy A. Crane as Rocky Mountain Power's chief executive officer. |
(3)Amounts consist of PacifiCorp K Plus Employee Savings Plan, or 401(k) Plan, contributions PacifiCorp paid on behalf of the NEOs.
(4)Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the Summary Compensation Table.
(5)In 2021, PacifiCorp reimbursed BHE $239,746 for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp pursuant to the intercompany administrative services agreement.
Pension Benefits
The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of PacifiCorp's NEOs as of December 31, 2018:2021:
|
| | | | | | | | |
| | | | Number of years of | | Present value of |
Name | | Plan name | | credited service | | accumulated benefits (1) |
| | | | | | |
William J. Fehrman | | n/a | | n/a | | n/a |
|
Gregory E. Abel | | n/a | | n/a | | n/a |
|
Stefan A. Bird | | Retirement | | 10 years | | $ | 206,774 |
|
Cindy A. Crane | | Retirement | | 21 years | | 468,923 |
|
Gary W. Hoogeveen | | n/a | | n/a | | n/a |
|
Nikki L. Kobliha | | Retirement | | 12 years | | 112,149 |
|
| | | | | | | | | | | | | | | | | | | | |
(1) | Amounts are computed using assumptions, other than the expected retirement age, consistent with those used in preparing the related pension disclosures in the Notes to Consolidated Financial Statements | | | Number of PacifiCorp in Item 8years of this Form 10-K and are as of December 31, 2018, which is the measurement date for the plans. The expected retirement age assumption has been determined in accordance with Instruction 2 to Item 402(h)(2) of Regulation S-K. For the Retirement Plan calculations of the present | | Present value of |
Name | | Plan name | | credited service | | accumulated benefits the following assumptions were used: 60% lump sum payment; 40% joint and 100% survivor annuity if participant is married and 40% single life annuity if participant is single. The present value assumptions used in calculating the present value of accumulated benefits for the(1) |
| | | | | | |
William J. Fehrman | | n/a | | n/a | | n/a |
Stefan A. Bird | | Retirement Plan were as follows: | | 10 years | | $ | 223,944 | |
Gary W. Hoogeveen | | n/a discount rate of 4.25%; an expected retirement age of 65; postretirement mortality using the RP-2014 gender specific tables, adjusted for BHE credibility weighted experience, translated to 2011 using MP-2014. 2012, 2013 and 2014 rates were used for MP-2016, MP-2017 and MP-2018, respectively and generational mortality improvements from 2014 forward were based on the custom RPEC 2014 v2018 model; | | n/a lump sum interest rate of 4.25%; and lump sum mortality using the gender specific tables set forth in IRC 417(e)(3) for the upcoming fiscal year with mortality improvements determined using MP-2017. | | n/a |
Nikki L. Kobliha | | Retirement | | 12 years | | 168,600 | |
(1)Amounts are computed using assumptions, other than the expected retirement age, consistent with those used in preparing the related pension disclosures in the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K and are as of December 31, 2021, which is the measurement date for the plans. The expected retirement age assumption has been determined in accordance with Instruction 2 to Item 402(h)(2) of Regulation S-K. For the Retirement Plan calculations of the present value of accumulated benefits, the following assumptions were used: 80% lump sum payment; 20% joint and 100% survivor annuity if participant is married and 20% single life annuity if participant is single. For 2023 and beyond, the lump sum payment assumption decreases from 80% to 60%, and the annuity assumption increases from 20% to 40%. The present value assumptions used in calculating the present value of accumulated benefits for the Retirement Plan were as follows: a discount rate of 2.90%; an expected retirement age of 65; cash balance interest crediting assumption of 0.88% for 2022 and 2023, and 1.90% thereafter; postretirement mortality using the Pri-2012 gender specific tables; generational mortality improvements from 2012 forward based on MP-2021; a lump sum interest rate of 2.90%; and lump sum mortality using the unisex tables set forth in IRC 417(e)(3) for the upcoming fiscal year with mortality improvements determined using MP-2020.
Historically, PacifiCorp has adopted the Retirement Plan for the majority of its employees, other than employees subject to collective bargaining agreements that do not provide for coverage under the Retirement Plan. Through May 31, 2007, participants earned benefits at retirement payable for life based on length of service through May 31, 2007 and average pay in the 60 consecutive months of highest pay out of the 120 months prior to May 31, 2007. Pay for this purpose included base salary and annual incentive plan payments up to 10% of base salary, but was limited to the amounts specified in Internal Revenue Code Section 401(a)(17). Benefits were based on 1.3% of final average pay plus 0.65% of final average pay in excess of covered compensation (as defined in Internal Revenue Code Section 401(1)(5)(E)) multiplied by years of service.
The Retirement Plan was restated effective June 1, 2007 to change from a traditional final average pay formula as described above to a cash balance formula for non-union participants. Benefits under the final average pay formula were frozen as of May 31, 2007, and no future benefits will accrue under that formula for non-union participants. Under the cash balance formula, benefits are based on pay credits to each participant's account of 6.5% (5.0% for employees hired after June 30, 2006 and before January 1, 2008) of eligible compensation. In addition, through August 1, 2009, there was a pay credit of 4% of eligible compensation in excess of the Social Security Wage Base. Interest is also credited to each participant's account. Employees who were age 40 or older as of May 31, 2007 received certain additional transition pay credits for five years from the effective date of the Retirement Plan restatement.
Participants in the Retirement Plan are entitled to receive full benefits upon retirement on or after age 65. Such participants are also entitled to receive reduced benefits upon early retirement after age 55 with at least five years of service or when age plus years of service equals 75.
The Retirement Plan was closed to non-union employees hired after December 31, 2007 (which includes Mr. Hoogeveen). In 2008, non-union employee participants in the Retirement Plan were offered the option to continue to receive pay credits in the Retirement Plan or receive equivalent fixed contributions to the 401(k) Plan with any such election becoming effective January 1, 2009. Ms. Kobliha and Mr. Hoogeveen elected the equivalent fixed 401(k) contribution option and, therefore, no longer receivereceives pay credits in the Retirement Plan. In 2017, the Retirement Plan was frozen for the remainder of the non-union employees who had participated (which includeincludes Mr. Bird, and Ms. Crane)Bird) with pay credits equivalent to those received in the Retirement Plan allocated into the K Plus Employee Savings401(k) Plan. Each NEO continuesMr. Bird and Ms. Kobliha continue to receive interest credits in the Retirement Plan.
Nonqualified Deferred Compensation
The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of PacifiCorp's NEOs as of December 31, 2018:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Executive | | Registrant | | Aggregate | | Aggregate | | Aggregate |
| | contributions | | contributions | | earnings/losses | | withdrawals/ | | balance as of |
Name | | in 2021(1)(2) | | in 2021 | | in 2021 | | distributions | | 12/31/2021(3) |
| | | | | | | | | | |
William J. Fehrman | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Stefan A. Bird | | — | | | — | | | — | | | — | | | — | |
Gary W. Hoogeveen | | 321,836 | | | — | | | 388,591 | | | — | | | 3,866,753 | |
Nikki L. Kobliha | | 275,387 | | | — | | | 21,358 | | | — | | | 536,872 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Executive | | Registrant | | Aggregate | | Aggregate | | Aggregate |
| | contributions | | contributions | | earnings/losses | | withdrawals/ | | balance as of |
Name | | in 2018(1)(2)(3) | | in 2018 | | in 2018 | | distributions | | December 31, 2018 |
| | | | | | | | | | |
William J. Fehrman | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Gregory E. Abel | | — |
| | — |
| | — |
| | — |
| | — |
|
Stefan A. Bird | | — |
| | — |
| | — |
| | — |
| | — |
|
Cindy A. Crane | | 747,616 |
| | | | (153,453 | ) | | 99,555 |
| | 4,276,405 |
|
Gary W. Hoogeveen | | 310,272 |
| | — |
| | (71,213 | ) | | 142,984 |
| | 1,428,075 |
|
Nikki L. Kobliha | | 47,009 |
| | — |
| | — |
| | — |
| | 47,009 |
|
(1)The executive contribution amount shown for Mr. Hoogeveen represents a deferral of $321,836 of his 2018 LTIP award which was deferred in 2021. $177,747 of the deferred 2018 LTIP award is included in the 2021 total compensation reported for him in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2021.
(2)The executive contribution amount shown for Ms. Kobliha represents a deferral of $47,241 of her 2021 compensation and a deferral of $228,146 of her 2018 LTIP award which was deferred in 2021. $85,123 of the deferred 2018 LTIP award is included in the 2021 total compensation reported for her in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2021.
| |
(1) | The executive contribution amount shown for Ms. Crane represents a deferral of $447,762 of her 2014 LTIP award and $299,854 of her 2015 LTIP which were deferred in 2018. $69,530 of the deferred 2014 LTIP award and $46,563 of the deferred 2015 LTIP award is included in the total compensation reported for her in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2018. |
| |
(2) | The executive contribution amount shown for Mr. Hoogeveen represents a deferral of $310,272 of his 2015 LTIP award which was deferred in 2018. $96,495 of the deferred 2015 LTIP award is included in the 2018 total compensation reported for him in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2018. |
| |
(3) | The executive contribution amount shown for Ms. Kobliha represents a deferral of her 2015 LTIP award which was deferred in 2018. $7,759 of the deferred 2015 LTIP award is included in the 2018 total compensation reported for her in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2018. |
(3)The aggregate balance as of December 31, 2021, shown for Mr. Hoogeveen and Ms. Kobliha includes $389,955 and $51,580, respectively, of compensation previously reported in the Summary Compensation Table.
Eligibility for PacifiCorp's DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered by the plan and selected by the participant. Gains or losses are calculated daily, and returns are posted to accounts based on participants' fund allocation elections. Participants can change their fund allocations as of the end of any day on which the market is open.
The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement account, in-service account and education account. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments, except in the case of the four DCP transition accounts that allow for a grandfathered payout based on the previous deferred compensation plan distribution elections of lump sum, 5, 10 or 15 annual installments. Effective December 31, 2006, no new money may be deferred into the DCP transition accounts. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55), all amounts in the participant's account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.
Participants in PacifiCorp's LTIP also have the option of deferring all or a part of those awards after the four-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.
Potential Payments Upon Termination
PacifiCorp's NEOs other than the Chairman and CEO, are not generally entitled to severance or enhanced benefits upon termination of employment or change in control. Mr. Abel resignedNone of PacifiCorp's NEOs have an employment agreement; therefore, payments upon termination are determined by the applicable plan documents and our general employment policies and practices as PacifiCorp's Chairman and CEO on January 10, 2018 and received no severance or enhanced benefits in connection with his resignation.discussed below.
The following table sets forth the estimated increase in the present value of benefits pursuant to the termination scenarios indicated for PacifiCorp's NEOs, other than Mr. Fehrman and Mr. Abel.Fehrman. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 20182021 and are payable as lump sums unless otherwise noted.
| | Termination Scenario | | Incentive (1) | | Pension (2) | Termination Scenario | | Incentive (1) | | Pension (2) |
| | | | | | | | | |
Stefan A. Bird: | | | | | Stefan A. Bird: | |
Retirement, Voluntary and Involuntary With or Without Cause | | — |
| | 23,790 |
| Retirement, Voluntary and Involuntary With or Without Cause | | $ | — | | | $ | 25,849 | |
Death and Disability | | 1,021,409 |
| | 23,790 |
| Death and Disability | | 1,016,704 | | | 25,849 | |
Cindy A. Crane(3): | | | | | |
Involuntary With Cause | | — |
| | 30,545 |
| |
Retirement, Voluntary and Involuntary Without Cause, Death and Disability | | 1,434,981 |
| | 30,545 |
| |
Gary W. Hoogeveen: | | | | | Gary W. Hoogeveen: | |
Retirement, Voluntary and Involuntary With or Without Cause | | — |
| | n/a |
| Retirement, Voluntary and Involuntary With or Without Cause | | — | | | n/a |
Death and Disability | | 769,760 |
| | n/a |
| Death and Disability | | 858,232 | | | n/a |
Nikki L. Kobliha: | | | | | Nikki L. Kobliha: | |
Retirement, Voluntary and Involuntary With or Without Cause | | — |
| | — |
| Retirement, Voluntary and Involuntary With or Without Cause | | — | | | — | |
Death and Disability | | 156,550 |
| | — |
| Death and Disability | | 274,334 | | | — | |
| |
(1) | Amounts represent the unvested portion of each NEO's LTIP account, which becomes 100% vested under certain circumstances. |
| |
(2) | Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits table. |
| |
(3) | Ms. Crane has already met the retirement criteria, therefore her termination and death scenarios under the Retirement Plan are based on assuming 60% paid as a lump sum and 40% paid as a 100% joint and survivor annuity. |
(1)Amounts represent the unvested portion of each NEO's LTIP account, which becomes 100% vested under certain circumstances.
(2)Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits table.
Chief Executive Officer Pay Ratio
PacifiCorp's CEO receives no direct compensation from PacifiCorp, and no amounts are reported for the CEO in the Summary Compensation Table. Accordingly, PacifiCorp has determined that the CEO pay ratio is not calculable.
Director Compensation
PacifiCorp's directors do not receive additional compensation for service as directors of PacifiCorp. Compensation information for Messrs. Abel, Fehrman, Bird, Hoogeveen, and Ms. Kobliha for their services as executive officers of PacifiCorp is described above.
Compensation Committee Interlocks and Insider Participation
Mr. Fehrman is PacifiCorp's ChairmanChair and CEO and also the President and Chief Executive Officer of BHE. None of PacifiCorp's executive officers serves as a member of the compensation committee of any company that has an executive officer serving as a member of PacifiCorp's Board of Directors. None of PacifiCorp's executive officers serves as a member of the board of directors of any company (other than BHE) that has an executive officer serving as a member of PacifiCorp's compensation committee. See also PacifiCorp's Item 13 in this Annual Report on Form 10-K.
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, AND SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Beneficial Ownership
PacifiCorp is a consolidated subsidiary of BHE. PacifiCorp's common stock is indirectly owned by BHE, 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580. BHE is a consolidated subsidiary of Berkshire Hathaway that, as of February 21, 2019,January 31, 2022, owns 90.9%91.1% of BHE's common stock. The balance of BHE's common stock is beneficially owned by Walter Scott, Jr. (along with his family members and related or affiliated entities)entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, and Gregory E. Abel, BHE's Executive Chairman.Chair.
None of PacifiCorp's executive officers or directors owns shares of its preferred stock. The following table sets forth certain information regarding the beneficial ownership of BHE's common stock and the Class A and Class B shares of Berkshire Hathaway common stock held by each of PacifiCorp's directors, executive officers and all of its directors and executive officers as a group as of February 21, 2019:January 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | BHE | | Berkshire Hathaway |
| | Common Stock | | Class A Common Stock | | Class B Common Stock |
Beneficial Owner | | Number of Shares Beneficially Owned(1) | | Percentage of Class(1) | | Number of Shares Beneficially Owned(1) | | Percentage of Class(1) | | Number of Shares Beneficially Owned(1) | | Percentage of Class(1) |
| | | | | | | | | | | | |
William J. Fehrman | | — | | | — | | | — | | | — | | | — | | | — | |
Stefan A. Bird | | — | | | — | | | — | | | — | | | — | | | — | |
Calvin D. Haack | | — | | | — | | | — | | | — | | | — | | | — | |
Natalie L. Hocken | | — | | | — | | | — | | | — | | | — | | | — | |
Nikki L. Kobliha | | — | | | — | | | — | | | — | | | — | | | — | |
Gary W. Hoogeveen | | — | | | — | | | — | | | — | | | 512 | | | * |
All executive officers and directors as a group (6 persons) | | — | | | — | | | — | | | — | | | 512 | | | * |
|
| | | | | | | | | | | | | | | | | | |
| | BHE | | Berkshire Hathaway |
| | Common Stock | | Class A Common Stock | | Class B Common Stock |
Beneficial Owner | | Number of Shares Beneficially Owned(1) | | Percentage of Class(1) | | Number of Shares Beneficially Owned(1) | | Percentage of Class(1) | | Number of Shares Beneficially Owned(1) | | Percentage of Class(1) |
| | | | | | | | | | | | |
William J. Fehrman | | — |
| | — |
| | — |
| | — |
| | 50 |
| | * |
|
Stefan A. Bird | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Cindy A. Crane | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Patrick J. Goodman | | — |
| | — |
| | 5 |
| | * |
| | 786 |
| | * |
|
Natalie L. Hocken | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nikki L. Kobliha | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Gary W. Hoogeveen | | — |
| | — |
| | — |
| | — |
| | 1,073 |
| | * |
|
All executive officers and directors as a group (7 persons) | | — |
| | — |
| | 5 |
| | * |
| | 1,909 |
| | * |
|
* Indicates beneficial ownership of less than one percent of all outstanding shares.
| |
(1) | Includes shares of which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days. |
| |
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
(1)Includes shares of which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
Item 13.Certain Relationships and Related Transactions, and Director Independence
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, AND SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Certain Relationships and Related Transactions
The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the BHE Code of Business Conduct, or the Codes, which apply to all of PacifiCorp's directors, officers and employees and those of its subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which PacifiCorp or any of its subsidiaries participate and in which one or more of PacifiCorp's directors, executive officers, holders of more than five percent of its voting securities or any of such persons' immediate family members have a direct or indirect material interest.
Under the Codes, all of PacifiCorp's directors and executive officers (including those of its subsidiaries) must disclose to PacifiCorp's legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with its interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For PacifiCorp's chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway's audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with PacifiCorp's interests.
Under an intercompany administrative services agreement PacifiCorp has entered into with BHE and its other subsidiaries, the costs of certain administrative services provided by BHE to PacifiCorp or by PacifiCorp to BHE, or shared with BHE and other subsidiaries, are directly charged or allocated to the entity receiving such services. This agreement has been filed with the regulatory commissions in the states where PacifiCorp serves retail customers. PacifiCorp also provides an annual report of all transactions with its affiliates to its state regulatory commissions, who have the authority to refuse recovery in rates for payments PacifiCorp makes to its affiliates deemed to have the effect of subsidizing the separate business activities of BHE or its other subsidiaries.
Refer to Note 1921 of the Notes to the Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for additional information regarding related-partyrelated party transactions.
Director Independence
Because PacifiCorp's common stock is indirectly, wholly owned by BHE and its Board of Directors consists of BHE and PacifiCorp employees, PacifiCorp is not required to have independent directors or audit, nominating or compensation committees consisting of independent directors.
Based on the standards of the New York Stock Exchange LLC, on which the common stock of PacifiCorp's ultimate parent company, Berkshire Hathaway, is listed, PacifiCorp's Board of Directors has determined that none of its directors are considered independent because of their employment by BHE or PacifiCorp.
463
| |
Item 14. | Principal Accountant Fees and Services |
Item 14.Principal Accountant Fees and Services
The following table shows the fees paid or accrued by each Registrant for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP (PCAOB ID No. 34), the member firms of Deloitte Touche Tohmatsu Limited, and their respective affiliates (collectively, the "Deloitte Entities") for each of the last two years (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Berkshire | | | | | | | | | | | | |
| Hathaway | | | | MidAmerican | | MidAmerican | | Nevada | | Sierra | | Eastern |
| Energy(1) | | PacifiCorp | | Funding(1) | | Energy | | Power | | Pacific | | Energy Gas |
2021 | | | | | | | | | | | | | |
Audit fees(2) | $ | 11.3 | | | $ | 1.7 | | | $ | 1.3 | | | $ | 1.2 | | | $ | 0.9 | | | $ | 0.9 | | | $ | 1.2 | |
Audit-related fees(3) | 0.8 | | | 0.1 | | | 0.1 | | | 0.1 | | | — | | | — | | | 0.2 | |
Tax fees(4) | 0.1 | | | — | | | — | | | — | | | — | | | — | | | — | |
Total | $ | 12.2 | | | $ | 1.8 | | | $ | 1.4 | | | $ | 1.3 | | | $ | 0.9 | | | $ | 0.9 | | | $ | 1.4 | |
| | | | | | | | | | | | | |
2020 | | | | | | | | | | | | | |
Audit fees(2) | $ | 10.6 | | | $ | 1.5 | | | $ | 1.1 | | | $ | 1.0 | | | $ | 0.9 | | | $ | 0.9 | | | $ | 0.8 | |
Audit-related fees(3) | 0.7 | | | 0.1 | | | 0.2 | | | 0.2 | | | — | | | — | | | 0.4 | |
Tax fees(4) | 0.1 | | | — | | | — | | | — | | | — | | | — | | | — | |
Total | $ | 11.4 | | | $ | 1.6 | | | $ | 1.3 | | | $ | 1.2 | | | $ | 0.9 | | | $ | 0.9 | | | $ | 1.2 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Berkshire | | | | | | | | | | |
| Hathaway | | | | MidAmerican | | MidAmerican | | Nevada | | Sierra |
| Energy | | PacifiCorp | | Funding | | Energy | | Power | | Pacific |
2018 | | | | | | | | | | | |
Audit fees(1) | $ | 9.6 |
| | $ | 1.6 |
| | $ | 1.2 |
| | $ | 1.1 |
| | $ | 0.9 |
| | $ | 0.9 |
|
Audit-related fees(2) | 0.8 |
| | 0.3 |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
|
Tax fees(3) | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total | $ | 10.5 |
| | $ | 1.9 |
| | $ | 1.4 |
| | $ | 1.3 |
| | $ | 0.9 |
| | $ | 0.9 |
|
| | | | | | | | | | | |
2017 | | | | | | | | | | | |
Audit fees(1) | $ | 9.3 |
| | $ | 1.5 |
| | $ | 1.2 |
| | $ | 1.1 |
| | $ | 0.9 |
| | $ | 0.9 |
|
Audit-related fees(2) | 0.8 |
| | 0.2 |
| | 0.2 |
| | 0.2 |
| | — |
| | — |
|
Tax fees(3) | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total | $ | 10.2 |
| | $ | 1.7 |
| | $ | 1.4 |
| | $ | 1.3 |
| | $ | 0.9 |
| | $ | 0.9 |
|
(1)The reported fees for Berkshire Hathaway Energy include those fees reported for PacifiCorp, MidAmerican Funding, Nevada Power, Sierra Pacific and Eastern Energy Gas (since November 1, 2020 acquisition date totaling $0.9 million) while the reported fees for MidAmerican Funding include those fees reported for MidAmerican Energy.
(2)Audit fees include fees for the audit of the consolidated financial statements and interim reviews of the quarterly financial statements for each Registrant, audit services provided in connection with required statutory audits of certain of BHE's subsidiaries and comfort letters, consents and other services related to SEC matters for each Registrant.
| |
(1) | Audit fees include fees for the audit of the consolidated financial statements and interim reviews of the quarterly financial statements for each Registrant, audit services provided in connection with required statutory audits of certain of BHE's subsidiaries and comfort letters, consents and other services related to SEC matters for each Registrant. |
| |
(2) | Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain employee benefit plans and consultations on various accounting and reporting matters. |
| |
(3) | Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits. |
(3)Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain employee benefit plans and consultations on various accounting and reporting matters.
(4)Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits.
The audit committee has considered whether the non-audit services provided to the Registrants by the Deloitte Entities impaired the independence of the Deloitte Entities and concluded that they did not. All of the services performed by the Deloitte Entities were pre-approved in accordance with the pre-approval policy adopted by the audit committee. The policy provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the Deloitte Entities to the Registrants. The policy (a) identifies the guiding principles that must be considered by the audit committee in approving services to ensure that the Deloitte Entities' independence is not impaired; (b) describes the audit, audit-related and tax services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, requests to provide services that require specific approval by the audit committee will be submitted to the audit committee by both the Registrants' independent auditor and BHE's Chief Financial Officer. All requests for services to be provided by the independent auditor that do not require specific approval by the audit committee will be submitted to BHE's Chief Financial Officer and must include a detailed description of the services to be rendered. BHE's Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the audit committee. The audit committee will be informed on a timely basis of any such services rendered by the independent auditor.
PART IV
| |
Item 15. | Exhibits and Financial Statement Schedules |
Item 15.Exhibits and Financial Statement Schedules
| | | | | | | | | | | | | | | | | |
(a) | Financial Statements and Schedules | |
| | | | | |
| (1) | Financial Statements | |
| | | | | |
| | The financial statements of all Registrants are included in their respective Item 8 of this Form 10-K. | |
| | | | | |
| (2) | Financial Statement Schedules | |
| | | | | |
| | | |
| | | |
| | | | | |
| | Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto. | |
| | | | | |
| (3) | | |
| | |
| | | | | |
(b) | Exhibits |
| | | | | |
| | |
| | | | | |
Item 16.Form 10-K Summary
|
| | | | | |
(a) | Financial Statements and Schedules | |
| | | | | |
| (1) | Financial Statements | |
| | | | | |
| | The financial statements of all Registrants are included in their respective Item 8 of this Form 10-K. | |
| | |
| | | | | |
| (2) | Financial Statement Schedules | |
| | | | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | | | |
| | Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto. | |
| | | | | |
| (3) | | |
| | |
| | | | | |
(b) | Exhibits |
| | | | | |
| | |
| | | | | |
(c) | Financial statements required by Regulation S-X, which are excluded from the Annual Report by Rule 14a-3(b). | |
| | | | | |
| | |
| |
Item 16. | Form 10-K Summary |
None.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 18 | | | $ | 623 | |
| | | |
Accounts receivable - affiliate | 117 | | | 96 | |
Notes receivable - affiliate | 189 | | | 177 | |
Income tax receivable | 23 | | | 19 | |
Other current assets | 13 | | | 1,301 | |
Total current assets | 360 | | | 2,216 | |
| | | |
Investments in subsidiaries | 58,190 | | | 48,654 | |
Other investments | 237 | | | 6,103 | |
Goodwill | 1,221 | | | 1,221 | |
Other assets | 1,101 | | | 488 | |
| | | |
Total assets | $ | 61,109 | | | $ | 58,682 | |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable and other current liabilities | $ | 397 | | | $ | 341 | |
Notes payable - affiliate | 353 | | | 200 | |
| | | |
Current portion of BHE senior debt | — | | | 450 | |
Total current liabilities | 750 | | | 991 | |
| | | |
BHE senior debt | 13,003 | | | 12,997 | |
BHE junior subordinated debentures | 100 | | | 100 | |
Notes payable - affiliate | 2 | | | 116 | |
Other long-term liabilities | 560 | | | 1,468 | |
Total liabilities | 14,415 | | | 15,672 | |
| | | |
Equity: | | | |
BHE shareholders' equity: | | | |
Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding | 1,650 | | | 3,750 | |
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 6,374 | | | 6,377 | |
Long-term income tax receivable | (744) | | | (658) | |
Retained earnings | 40,754 | | | 35,093 | |
Accumulated other comprehensive loss, net | (1,340) | | | (1,552) | |
Total BHE shareholders' equity | 46,694 | | | 43,010 | |
Noncontrolling interest | — | | | — | |
Total equity | 46,694 | | | 43,010 | |
| | | |
Total liabilities and equity | $ | 61,109 | | | $ | 58,682 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 9 |
| | $ | 346 |
|
Accounts receivable - affiliate | 100 |
| | 60 |
|
Notes receivable - affiliate | 156 |
| | 391 |
|
Income tax receivable | 103 |
| | — |
|
Other current assets | 15 |
| | 21 |
|
Total current assets | 383 |
| | 818 |
|
| | | |
Investments in subsidiaries | 36,602 |
| | 34,019 |
|
Other investments | 1,579 |
| | 2,117 |
|
Goodwill | 1,221 |
| | 1,221 |
|
Other assets | 546 |
| | 1,155 |
|
| | | |
Total assets | $ | 40,331 |
| | $ | 39,330 |
|
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable and other current liabilities | $ | 183 |
| | $ | 268 |
|
Notes payable - affiliate | 328 |
| | 182 |
|
Short-term debt | 983 |
| | 3,331 |
|
Current portion of BHE senior debt | — |
| | 1,000 |
|
Total current liabilities | 1,494 |
| | 4,781 |
|
| | | |
BHE senior debt | 8,577 |
| | 5,452 |
|
BHE junior subordinated debentures | 100 |
| | 100 |
|
Notes payable - affiliate | 1 |
| | 1 |
|
Other long-term liabilities | 543 |
| | 800 |
|
Total liabilities | 10,715 |
| | 11,134 |
|
| | | |
Equity: | | | |
BHE shareholders' equity: | | | |
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding | — |
| | — |
|
Additional paid-in capital | 6,371 |
| | 6,368 |
|
Long-term income tax receivable | (457 | ) | | — |
|
Retained earnings | 25,624 |
| | 22,206 |
|
Accumulated other comprehensive loss, net | (1,945 | ) | | (398 | ) |
Total BHE shareholders' equity | 29,593 |
| | 28,176 |
|
Noncontrolling interest | 23 |
| | 20 |
|
Total equity | 29,616 |
| | 28,196 |
|
| | | |
Total liabilities and equity | $ | 40,331 |
| | $ | 39,330 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Operating expenses: | | | | | |
General and administration | $ | 83 | | | $ | 57 | | | $ | 49 | |
Depreciation and amortization | 6 | | | 4 | | | 5 | |
Total operating expenses | 89 | | | 61 | | | 54 | |
| | | | | |
Operating loss | (89) | | | (61) | | | (54) | |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (580) | | | (527) | | | (452) | |
Other, net | 1,846 | | | 4,789 | | | (271) | |
Total other income (expense) | 1,266 | | | 4,262 | | | (723) | |
| | | | | |
Income (loss) before income tax expense (benefit) and equity income | 1,177 | | | 4,201 | | | (777) | |
Income tax expense (benefit) | 194 | | | 1,089 | | | (312) | |
Equity income | 4,807 | | | 3,832 | | | 3,419 | |
Net income | 5,790 | | | 6,944 | | | 2,954 | |
Net income attributable to noncontrolling interest | — | | | 1 | | | 3 | |
Net income attributable to BHE shareholders | 5,790 | | | 6,943 | | | 2,951 | |
Preferred dividends | 121 | | | 26 | | | — | |
Earnings on common shares | $ | 5,669 | | | $ | 6,917 | | | $ | 2,951 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Operating expenses: | | | | | |
General and administration | $ | 21 |
| | $ | 55 |
| | $ | 51 |
|
Depreciation and amortization | 4 |
| | 4 |
| | 4 |
|
Total operating expenses | 25 |
| | 59 |
| | 55 |
|
| | | | | |
Operating loss | (25 | ) | | (59 | ) | | (55 | ) |
| | | | | |
Other income (expense): | | | | | |
Interest expense | (438 | ) | | (475 | ) | | (527 | ) |
Other, net | (537 | ) | | (369 | ) | | 37 |
|
Total other income (expense) | (975 | ) | | (844 | ) | | (490 | ) |
| | | | | |
Loss before income tax benefit and equity income | (1,000 | ) | | (903 | ) | | (545 | ) |
Income tax benefit | (513 | ) | | (335 | ) | | (285 | ) |
Equity income | 3,058 |
| | 3,441 |
| | 2,805 |
|
Net income | 2,571 |
| | 2,873 |
| | 2,545 |
|
Net income attributable to noncontrolling interest | 3 |
| | 3 |
| | 3 |
|
Net income attributable to BHE shareholders | $ | 2,568 |
| | $ | 2,870 |
| | $ | 2,542 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net income | $ | 5,790 | | | $ | 6,944 | | | $ | 2,954 | |
Other comprehensive income, net of tax | 212 | | | 154 | | | 239 | |
Comprehensive income | 6,002 | | | 7,098 | | | 3,193 | |
Comprehensive income attributable to noncontrolling interests | — | | | 1 | | | 3 | |
Comprehensive income attributable to BHE shareholders | $ | 6,002 | | | $ | 7,097 | | | $ | 3,190 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 2,571 |
| | $ | 2,873 |
| | $ | 2,545 |
|
Other comprehensive income (loss), net of tax | (462 | ) | | 1,113 |
| | (603 | ) |
Comprehensive income | 2,109 |
| | 3,986 |
| | 1,942 |
|
Comprehensive income attributable to noncontrolling interests | 3 |
| | 3 |
| | 3 |
|
Comprehensive income attributable to BHE shareholders | $ | 2,106 |
| | $ | 3,983 |
| | $ | 1,939 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Cash flows from operating activities | $ | 1,819 | | | $ | 1,639 | | | $ | 1,780 | |
| | | | | |
Cash flows from investing activities: | | | | | |
Investments in subsidiaries | (1,206) | | | (6,422) | | | (1,972) | |
Purchases of marketable securities | (29) | | | (55) | | | (42) | |
Proceeds from sales of marketable securities | 28 | | | 22 | | | 41 | |
Purchases of other investments | — | | | (1,290) | | | — | |
Proceeds from other investments | 1,290 | | | — | | | 1 | |
Notes receivable from affiliate, net | 200 | | | (121) | | | (112) | |
Other, net | (20) | | | (20) | | | (5) | |
Net cash flows from investing activities | 263 | | | (7,886) | | | (2,089) | |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from issuance of preferred stock | — | | | 3,750 | | | — | |
Preferred stock redemptions | (2,100) | | | — | | | — | |
Preferred dividends | (132) | | | (7) | | | — | |
Common stock purchases | — | | | (126) | | | (293) | |
Proceeds from BHE senior debt | — | | | 5,212 | | | — | |
| | | | | |
| | | | | |
Repayments of BHE senior debt | (450) | | | (350) | | | — | |
| | | | | |
Net (repayments of) proceeds from short-term debt | — | | | (1,590) | | | 607 | |
| | | | | |
| | | | | |
Other, net | (5) | | | (32) | | | (1) | |
Net cash flows from financing activities | (2,687) | | | 6,857 | | | 313 | |
| | | | | |
Net change in cash and cash equivalents | (605) | | | 610 | | | 4 | |
Cash and cash equivalents at beginning of year | 623 | | | 13 | | | 9 | |
Cash and cash equivalents at end of year | $ | 18 | | | $ | 623 | | | $ | 13 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Cash flows from operating activities | $ | 1,885 |
| | $ | 2,450 |
| | $ | 2,760 |
|
| | | | | |
Cash flows from investing activities: | | | | | |
Investments in subsidiaries | (1,791 | ) | | (1,566 | ) | | (1,080 | ) |
Purchases of investments | (44 | ) | | (71 | ) | | (24 | ) |
Proceeds from sale of investments | 45 |
| | 68 |
| | 20 |
|
Notes receivable from affiliate, net | (72 | ) | | (305 | ) | | (307 | ) |
Other, net | (22 | ) | | (8 | ) | | (5 | ) |
Net cash flows from investing activities | (1,884 | ) | | (1,882 | ) | | (1,396 | ) |
| | | | | |
Cash flows from financing activities: | | | | | |
Proceeds from BHE senior debt | 3,166 |
| | — |
| | — |
|
Repayments of BHE senior debt | (1,045 | ) | | (1,379 | ) | | — |
|
Repayments of BHE subordinated debt | — |
| | (944 | ) | | (2,000 | ) |
Common stock purchases | (107 | ) | | (19 | ) | | — |
|
Net proceeds from (repayments of) short-term debt | (2,348 | ) | | 2,498 |
| | 581 |
|
Tender offer premium paid | — |
| | (406 | ) | | — |
|
Notes payable to affiliate, net | — |
| | — |
| | 69 |
|
Other, net | (4 | ) | | (5 | ) | | (4 | ) |
Net cash flows from financing activities | (338 | ) | | (255 | ) | | (1,354 | ) |
| | | | | |
Net change in cash and cash equivalents | (337 | ) | | 313 |
| | 10 |
|
Cash and cash equivalents at beginning of year | 346 |
| | 33 |
| | 23 |
|
Cash and cash equivalents at end of year | $ | 9 |
| | $ | 346 |
| | $ | 33 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Basis of Presentation - The condensed financial information of BHE investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in subsidiaries are recorded in the Condensed Balance Sheets. The income from operations of subsidiaries is reported on a net basis as equity income in the Condensed Statements of Operations.
Other investments - BHE's investment in BYD Company Limited ("BYD") common stock is accounted for as an available-for-salea marketable security with changes in fair value recognized in AOCI.net income. As of December 31, 20182021 and 2017,2020, the fair value of BHE's investment in BYD common stock was $1,435$— million and $1,961$5,897 million, respectively, which resulted in an unrealized gain of $1,203 million and $1,729 million as of December 31, 2018 and 2017, respectively.
Dividends and distributions from subsidiaries - Cash dividends paid to BHE by its subsidiaries for the years ended December 31, 2018, 20172021, 2020 and 20162019 were $2.3$2.4 billion, $3.0$2.0 billion and $3.0$2.0 billion, respectively. In January and February 2019,2022, BHE received cash dividends from its subsidiaries totaling $194 million.$102 million.
Guarantees and commitments - BHE has issued guarantees and letters of credit in respect of subsidiary andsubsidiaries, equity method investments and other related parties aggregating $297 million$1.4 billion and commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $1,383$356 million.
See the notes to the consolidated BHE financial statements in Part II, Item 8 for other disclosures regarding long-term obligations (Notes 8, 9, 10 and 10)11) and shareholders' equity (Note 16)18).
Schedule II
BERKSHIRE HATHAWAY ENERGY COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2018
(Amounts in millions)
|
| | | | | | | | | | | | | | | | | | | | |
| | Column B | | Column C | | | Column E |
| | Balance at | | Charged | | | | | | Balance |
Column A | | Beginning | | to | | Acquisition | | Column D | | at End |
Description | | of Year | | Income | | Reserves | | Deductions | | of Year |
| | | | | | | | | | |
Reserves Deducted From Assets To Which They Apply: | | | | | | | | |
| | | | | | | | | | |
Reserve for uncollectible accounts receivable: | | | | | | | | | | |
Year ended 2018 | | $ | 40 |
| | $ | 43 |
| | $ | — |
| | $ | (41 | ) | | $ | 42 |
|
Year ended 2017 | | 33 |
| | 42 |
| | — |
| | (35 | ) | | 40 |
|
Year ended 2016 | | 31 |
| | 39 |
| | — |
| | (37 | ) | | 33 |
|
| | | | | | | | | | |
Reserves Not Deducted From Assets(1): | | | | | | | | | | |
Year ended 2018 | | $ | 13 |
| | $ | 6 |
| | $ | — |
| | $ | (6 | ) | | $ | 13 |
|
Year ended 2017 | | 13 |
| | 7 |
| | — |
| | (7 | ) | | 13 |
|
Year ended 2016 | | 13 |
| | 5 |
| | — |
| | (5 | ) | | 13 |
|
The notes to the consolidated BHE financial statements are an integral part of this financial statement schedule.
| |
(1) | Reserves not deducted from assets relate primarily to estimated liabilities for losses retained by BHE for workers compensation, public liability and property damage claims. |
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)
| | | | | | | | | | | |
| As of December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Receivables from affiliates | $ | 1 | | | $ | 1 | |
| | | |
| | | |
| | | |
Investments in and advances to subsidiaries | 10,070 | | | 9,176 | |
| | | |
Total assets | $ | 10,071 | | | $ | 9,177 | |
| | | |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Interest accrued and other current liabilities | $ | 5 | | | $ | 5 | |
| | | |
| | | |
Payable to affiliate | 25 | | | 13 | |
Long-term debt | 240 | | | 240 | |
| | | |
Total liabilities | 270 | | | 258 | |
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 | | | 1,679 | |
Retained earnings | 8,122 | | | 7,240 | |
| | | |
Total member's equity | 9,801 | | | 8,919 | |
| | | |
Total liabilities and member's equity | $ | 10,071 | | | $ | 9,177 | |
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
ASSETS |
Current assets: | | | |
Receivables from affiliates | $ | 2 |
| | $ | 2 |
|
Income tax receivable | — |
| | 13 |
|
Total current assets | 2 |
| | 15 |
|
| | | |
Investments in and advances to subsidiaries | 8,002 |
| | 7,322 |
|
| | | |
Total assets | $ | 8,004 |
| | $ | 7,337 |
|
| | | |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Interest accrued and other current liabilities | $ | 6 |
| | $ | 6 |
|
| | | |
Payable to affiliate | 429 |
| | 431 |
|
Long-term debt | 240 |
| | 240 |
|
Total liabilities | 675 |
| | 677 |
|
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 |
| | 1,679 |
|
Retained earnings | 5,650 |
| | 4,981 |
|
Total member's equity | 7,329 |
| | 6,660 |
|
| | | |
Total liabilities and member's equity | $ | 8,004 |
| | $ | 7,337 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Other income and (expense): | | | | | |
Interest expense | $ | (16) | | | $ | (16) | | | $ | (16) | |
| | | | | |
Loss before income taxes | (16) | | | (16) | | | (16) | |
Income tax benefit | (5) | | | (5) | | | (5) | |
Equity in undistributed earnings of subsidiaries | 894 | | | 829 | | | 792 | |
Net income | $ | 883 | | | $ | 818 | | | $ | 781 | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Other income and (expense): | | | | | |
Interest expense | $ | (16 | ) | | $ | (22 | ) | | $ | (22 | ) |
Other, net | — |
| | (30 | ) | | — |
|
Loss before income taxes | (16 | ) | | (52 | ) | | (22 | ) |
Income tax benefit | (5 | ) | | (22 | ) | | (9 | ) |
Equity in undistributed earnings of subsidiaries | 680 |
| | 604 |
| | 545 |
|
Net income | $ | 669 |
| | $ | 574 |
| | $ | 532 |
|
The accompanying notes are an integral part of this financial statement schedule.
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 669 |
| | $ | 574 |
| | $ | 532 |
|
Total other comprehensive income, net of tax | — |
| | — |
| | 3 |
|
| | | | | |
Comprehensive income | $ | 669 |
| | $ | 574 |
| | $ | 535 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
Net cash flows from operating activities | $ | (12) | | | $ | (12) | | | $ | (12) | |
| | | | | |
| | | | | |
| | | | | |
Net cash flows from investing activities | — | | | — | | | — | |
| | | | | |
Net cash flows from financing activities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
Net change in amounts payable to subsidiary | 12 | | | 12 | | | 12 | |
Net cash flows from financing activities | 12 | | | 12 | | | 12 | |
| | | | | |
Net change in cash and cash equivalents | — | | | — | | | — | |
Cash and cash equivalents at beginning of year | — | | | — | | | — | |
Cash and cash equivalents at end of year | $ | — | | | $ | — | | | $ | — | |
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net cash flows from operating activities | $ | 2 |
| | $ | (15 | ) | | $ | (13 | ) |
| | | | | |
Net cash flows from investing activities | — |
| | — |
| | — |
|
| | | | | |
Net cash flows from financing activities: | | | | | |
Repayment of long-term debt | — |
| | (86 | ) | | — |
|
Tender offer premium paid | — |
| | (29 | ) | | — |
|
Net change in amounts payable to subsidiary | (2 | ) | | 130 |
| | 13 |
|
Net cash flows from financing activities | (2 | ) | | 15 |
| | 13 |
|
| | | | | |
Net change in cash and cash equivalents | — |
| | — |
| | — |
|
Cash and cash equivalents at beginning of year | — |
| | — |
| | — |
|
Cash and cash equivalents at end of year | $ | — |
| | $ | — |
| | $ | — |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are MidAmerican Funding, LLC and Subsidiaries Consolidated Statements of Changes in Equity for the three years ended December 31, 20182021 in Part II, Item 8.
Basis of Presentation - The condensed financial information of MidAmerican Funding, LLC's ("MidAmerican Funding's") investments in subsidiaries is presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded on the Condensed Balance Sheets. The income from operations of the subsidiaries is reported on a net basis as equity in undistributed earnings of subsidiary companies on the Condensed Statements of Operations. The Condensed Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2021, 2020 and 2019.
Income Taxes - MidAmerican Funding is not subject to income tax and is disregarded by the taxing authorities. However, a portion of Berkshire Hathaway Inc.'s consolidated income tax expense has been allocated to MidAmerican Funding for presentation in its separate financial statements commensurate with computing MidAmerican Funding's provision on a stand-alone basis.
Payable to Affiliate - MHC, Inc. ("MHC") settles all obligations of MidAmerican Funding including primarily interest costs on, and repayments of, MidAmerican Funding's long-term debt and income taxes. MHC received $2paid $12 million in 20182021, 2020 and paid $130 million and $13 million for the years 2017 and 2016, respectively,2019 on behalf of MidAmerican Funding. In 2019, MHC transferred to MidAmerican Funding $440 million of its receivable from MidAmerican Funding in the form of a dividend.
Distribution to Parent - In 2019, MidAmerican Funding recorded a noncash dividend of $8 million for the transfer to BHE of corporate aircraft owned by MHC.
See the notes to the consolidated MidAmerican Funding financial statements in Part II, Item 8 for other disclosures.
Schedule I
MHC INC.
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 1 |
| | $ | — |
|
Receivables from affiliates | — |
| | 2 |
|
| | | |
Receivable from parent | 429 |
| | 431 |
|
Investments and nonregulated property, net | 12 |
| | 14 |
|
Goodwill | 1,270 |
| | 1,270 |
|
Investments in and advances to subsidiaries | 6,465 |
| | 5,783 |
|
| | | |
Total assets | $ | 8,177 |
| | $ | 7,500 |
|
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Payables to affiliates | $ | 172 |
| | $ | 175 |
|
| | | |
Deferred income taxes | 3 |
| | 3 |
|
Total liabilities | 175 |
| | 178 |
|
| | | |
Shareholder's equity: | | | |
Paid-in capital | 2,430 |
| | 2,430 |
|
Retained earnings | 5,572 |
| | 4,892 |
|
Total shareholder's equity | 8,002 |
| | 7,322 |
|
| | | |
Total liabilities and shareholder's equity | $ | 8,177 |
| | $ | 7,500 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MHC INC.
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Other income | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
Other interest expense | 4 |
| | — |
| | — |
|
Income before income taxes | (3 | ) | | 1 |
| | 1 |
|
Income tax expense | (1 | ) | | — |
| | — |
|
Equity in undistributed earnings of subsidiaries | 682 |
| | 603 |
| | 544 |
|
Net income | $ | 680 |
| | $ | 604 |
| | $ | 545 |
|
EXHIBIT INDEX
The accompanying notes are an integral part of this financial statement schedule.
MHC INC.
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 680 |
| | $ | 604 |
| | $ | 545 |
|
Total other comprehensive income, net of tax | — |
| | — |
| | 3 |
|
| | | | | |
Comprehensive income | $ | 680 |
| | $ | 604 |
| | $ | 548 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MHC INC.
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net cash flows from operating activities | $ | 5 |
| | $ | (1 | ) | | $ | 1 |
|
| | | | | |
Net cash flows from investing activities: | | | | | |
Capital expenditures | — |
| | (2 | ) | | (1 | ) |
Net change in amounts receivable from parent | 2 |
| | (130 | ) | | (13 | ) |
Net cash flows from investing activities | 2 |
| | (132 | ) | | (14 | ) |
| | | | | |
Net cash flows from financing activities: | | | | | |
Net change in amounts payable to subsidiaries | 2 |
| | (1 | ) | | 5 |
|
Net change in note payable to Berkshire Hathaway Energy Company | (8 | ) | | 133 |
| | 9 |
|
Net cash flows from financing activities | (6 | ) | | 132 |
| | 14 |
|
| | | | | |
Net change in cash and cash equivalents | 1 |
| | (1 | ) | | 1 |
|
Cash and cash equivalents at beginning of year | — |
| | 1 |
| | — |
|
Cash and cash equivalents at end of year | $ | 1 |
| | $ | — |
| | $ | 1 |
|
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MHC INC.
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are MHC Inc. and Subsidiaries Consolidated Statements of Changes in Equity for the three years ended December 31, 2018, in Part IV, Item 15(c).
Basis of Presentation - The condensed financial information of MHC Inc.'s ("MHC's") investments in subsidiaries is presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded on the Condensed Balance Sheets. The income from operations of the subsidiaries is reported on a net basis as equity in undistributed earnings of subsidiary companies on the Condensed Statements of Operations.
Receivable from Parent - MHC settles all obligations of MidAmerican Funding, LLC ("MidAmerican Funding") including primarily interest costs on, and repayments of, MidAmerican Funding's long-term debt and income taxes. MHC received $2 million in 2018 and paid $130 million and $13 million for the years 2017 and 2016, respectively, on behalf of MidAmerican Funding.
Note Payable to Berkshire Hathaway Energy Company - On January 1, 2016, MidAmerican Energy Company transferred the assets and liabilities of its unregulated retail services business to a subsidiary of Berkshire Hathaway Energy Company ("BHE"). The transfer repaid $117 million of MHC's note payable to BHE.
See the notes to the consolidated MHC financial statements in Part IV, Item 15(c) for other disclosures.
Schedule II
MIDAMERICAN ENERGY COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2018
(Amounts in millions)
|
| | | | | | | | | | | | | | | | |
| | Column B | | Column C | | | | Column E |
| | Balance at | | Additions | | | | Balance |
Column A | | Beginning | | Charged | | Column D | | at End |
Description | | of Year | | to Income | | Deductions | | of Year |
| | | | | | | | |
Reserves Deducted From Assets To Which They Apply: | | | | | | | | |
Reserve for uncollectible accounts receivable: | | | | | | | | |
| | | | | | | | |
Year ended 2018 | | $ | 7 |
| | $ | 8 |
| | $ | (8 | ) | | $ | 7 |
|
| | | | | | | | |
Year ended 2017 | | $ | 7 |
| | $ | 8 |
| | $ | (8 | ) | | $ | 7 |
|
| | | | | | | | |
Year ended 2016 | | $ | 6 |
| | $ | 7 |
| | $ | (6 | ) | | $ | 7 |
|
| | | | | | | | |
| | | | | | | | |
Reserves Not Deducted From Assets(1): | | | | | | | | |
| | | | | | | | |
Year ended 2018 | | $ | 13 |
| | $ | 6 |
| | $ | (6 | ) | | $ | 13 |
|
| | | | | | | | |
Year ended 2017 | | $ | 13 |
| | $ | 7 |
| | $ | (7 | ) | | $ | 13 |
|
| | | | | | | | |
Year ended 2016 | | $ | 13 |
| | $ | 5 |
| | $ | (5 | ) | | $ | 13 |
|
| | | | | |
(1)Exhibit No. | Reserves not deducted from assets include estimated liabilities for losses retained by MidAmerican Energy for workers compensation, public liability and property damage claims. |
Schedule II
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
MHC INC. AND SUBSIDIARIES
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2018
(Amounts in millions)
|
| | | | | | | | | | | | | | | | |
| | Column B | | Column C | | | | Column E |
| | Balance at | | Additions | | | | Balance |
Column A | | Beginning | | Charged | | Column D | | at End |
Description | | of Year | | to Income | | Deductions | | of Year |
| | | | | | | | |
Reserves Deducted From Assets To Which They Apply: | | | | | | | | |
Reserve for uncollectible accounts receivable: | | | | | | | | |
| | | | | | | | |
Year ended 2018 | | $ | 7 |
| | $ | 8 |
| | $ | (8 | ) | | $ | 7 |
|
| | | | | | | | |
Year ended 2017 | | $ | 7 |
| | $ | 8 |
| | $ | (8 | ) | | $ | 7 |
|
| | | | | | | | |
Year ended 2016 | | $ | 6 |
| | $ | 7 |
| | $ | (6 | ) | | $ | 7 |
|
| | | | | | | | |
| | | | | | | | |
Reserves Not Deducted From Assets (1): | | | | | | | | |
| | | | | | | | |
Year ended 2018 | | $ | 13 |
| | $ | 6 |
| | $ | (6 | ) | | $ | 13 |
|
| | | | | | | | |
Year ended 2017 | | $ | 13 |
| | $ | 7 |
| | $ | (7 | ) | | $ | 13 |
|
| | | | | | | | |
Year ended 2016 | | $ | 13 |
| | $ | 5 |
| | $ | (5 | ) | | $ | 13 |
|
| |
(1) | Reserves not deducted from assets include primarily estimated liabilities for losses retained by MidAmerican Funding and MHC for workers compensation, public liability and property damage claims. |
The accompanying Consolidated Financial Statements of MHC Inc., the direct wholly owned subsidiary of MidAmerican Funding, are being provided pursuant to Rule 3-16 of the U. S. Securities and Exchange Commission's Regulation S-X. The purpose of these financial statements is to provide information about the assets and equity interests that collateralize MidAmerican Funding's long-term debt and that, upon the occurrence of any triggering event under the collateral agreement, would be available to satisfy the applicable debt obligations.
|
| |
MHC Inc. and its subsidiaries | |
| |
| |
| |
| |
| |
| |
| Description |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
MHC Inc.
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of MHC Inc. and subsidiaries ("MHC") as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income, changes in shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and the schedules listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MHC as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of MHC's management. Our responsibility is to express an opinion on MHC's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MHC in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MHC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MHC's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
February 22, 2019
We have served as MHC's auditor since 1999.
MHC INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 1 |
| | $ | 172 |
|
Accounts receivable, net | 363 |
| | 346 |
|
Income taxes receivable | — |
| | 51 |
|
Inventories | 204 |
| | 245 |
|
Other current assets | 90 |
| | 135 |
|
Total current assets | 658 |
| | 949 |
|
| | | |
Property, plant and equipment, net | 16,171 |
| | 14,221 |
|
Goodwill | 1,270 |
| | 1,270 |
|
Regulatory assets | 273 |
| | 204 |
|
Investments and restricted investments | 710 |
| | 730 |
|
Receivable from affiliate | 429 |
| | 431 |
|
Other assets | 119 |
| | 233 |
|
| | | |
Total assets | $ | 19,630 |
| | $ | 18,038 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MHC INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 575 |
| | $ | 451 |
|
Accrued interest | 53 |
| | 48 |
|
Accrued property, income and other taxes | 300 |
| | 133 |
|
Note payable to affiliate | 156 |
| | 164 |
|
Short-term debt | 240 |
| | — |
|
Current portion of long-term debt | 500 |
| | 350 |
|
Other current liabilities | 122 |
| | 128 |
|
Total current liabilities | 1,946 |
| | 1,274 |
|
| | | |
Long-term debt | 4,881 |
| | 4,692 |
|
Regulatory liabilities | 1,620 |
| | 1,661 |
|
Deferred income taxes | 2,319 |
| | 2,235 |
|
Asset retirement obligations | 552 |
| | 528 |
|
Other long-term liabilities | 310 |
| | 326 |
|
Total liabilities | 11,628 |
| | 10,716 |
|
| | | |
Commitments and contingencies (Note 13) | | | |
| | | |
Shareholder's equity: | | | |
Common stock - no par value, 1,000 shares authorized, 1,000 shares issued and outstanding | — |
| | — |
|
Additional paid-in capital | 2,430 |
| | 2,430 |
|
Retained earnings | 5,572 |
| | 4,892 |
|
Total shareholder's equity | 8,002 |
| | 7,322 |
|
| | | |
Total liabilities and shareholder's equity | $ | 19,630 |
| | $ | 18,038 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,283 |
| | $ | 2,108 |
| | $ | 1,985 |
|
Regulated natural gas and other | 770 |
| | 738 |
| | 646 |
|
Total operating revenue | 3,053 |
| | 2,846 |
| | 2,631 |
|
| | | | | |
Operating expenses: | | | | | |
Cost of fuel and energy | 487 |
| | 434 |
| | 410 |
|
Cost of natural gas purchased for resale and other | 469 |
| | 447 |
| | 371 |
|
Operations and maintenance | 813 |
| | 802 |
| | 708 |
|
Depreciation and amortization | 609 |
| | 500 |
| | 479 |
|
Property and other taxes | 125 |
| | 119 |
| | 112 |
|
Total operating expenses | 2,503 |
| | 2,302 |
| | 2,080 |
|
| | | | | |
Operating income | 550 |
| | 544 |
| | 551 |
|
| | | | | |
Other income (expense): | | | | | |
Interest expense | (231 | ) | | (215 | ) | | (196 | ) |
Allowance for borrowed funds | 20 |
| | 15 |
| | 8 |
|
Allowance for equity funds | 53 |
| | 41 |
| | 19 |
|
Other, net | 31 |
| | 39 |
| | 33 |
|
Total other income (expense) | (127 | ) | | (120 | ) | | (136 | ) |
| | | | | |
Income before income tax benefit | 423 |
| | 424 |
| | 415 |
|
Income tax benefit | (257 | ) | | (180 | ) | | (130 | ) |
| | | | | |
Net income | $ | 680 |
| | $ | 604 |
| | $ | 545 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
| | | | | |
Net income | $ | 680 |
| | $ | 604 |
| | $ | 545 |
|
| | | | | |
Other comprehensive income, net of tax: | | | | | |
Unrealized gains on marketable securities, net of tax of $-, $- and $1 | — |
| | — |
| | 3 |
|
| | | | | |
Comprehensive income | $ | 680 |
| | $ | 604 |
| | $ | 548 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions)
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | Accumulated | | |
| | | | | | | Other | | Total |
| Common | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| Stock | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | |
Balance, December 31, 2015 | $ | — |
| | $ | 2,430 |
| | $ | 3,744 |
| | $ | (30 | ) | | $ | 6,144 |
|
Net income | — |
| | — |
| | 545 |
| | — |
| | 545 |
|
Other comprehensive income | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Transfer unregulated retail services business to affiliate | — |
| | — |
| | — |
| | 27 |
| | 27 |
|
Other equity transactions | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Balance, December 31, 2016 | — |
| | 2,430 |
| | 4,288 |
| | — |
| | 6,718 |
|
Net income | — |
| | — |
| | 604 |
| | — |
| | 604 |
|
Balance, December 31, 2017 | — |
| | 2,430 |
| | 4,892 |
| | — |
| | 7,322 |
|
Net income | — |
| | — |
| | 680 |
| | — |
| | 680 |
|
Balance, December 31, 2018 | $ | — |
| | $ | 2,430 |
| | $ | 5,572 |
| | $ | — |
| | $ | 8,002 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Cash flows from operating activities: | | | | | |
Net income | $ | 680 |
| | $ | 604 |
| | $ | 545 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | | | |
Depreciation and amortization | 609 |
| | 500 |
| | 479 |
|
Amortization of utility plant to other operating expenses | 34 |
| | 34 |
| | 37 |
|
Allowance for equity funds | (53 | ) | | (41 | ) | | (19 | ) |
Deferred income taxes and amortization of investment tax credits | 32 |
| | 334 |
| | 362 |
|
Other, net | 16 |
| | (13 | ) | | (63 | ) |
Changes in other operating assets and liabilities: | | | | | |
Accounts receivable and other assets | (19 | ) | | (63 | ) | | (60 | ) |
Inventories | 41 |
| | 19 |
| | (27 | ) |
Derivative collateral, net | (1 | ) | | 2 |
| | 5 |
|
Contributions to pension and other postretirement benefit plans, net | (13 | ) | | (11 | ) | | (6 | ) |
Accrued property, income and other taxes, net | 217 |
| | (42 | ) | | 107 |
|
Accounts payable and other liabilities | (29 | ) | | 72 |
| | 46 |
|
Net cash flows from operating activities | 1,514 |
| | 1,395 |
| | 1,406 |
|
| | | | | |
Net cash flows from investing activities: | | | | | |
Capital expenditures | (2,332 | ) | | (1,773 | ) | | (1,636 | ) |
Purchases of marketable securities | (263 | ) | | (143 | ) | | (138 | ) |
Proceeds from sales of marketable securities | 223 |
| | 137 |
| | 158 |
|
Proceeds from sales of other investments | 17 |
| | 2 |
| | 2 |
|
Other investment proceeds | 15 |
| | 1 |
| | — |
|
Net change in amounts receivable from parent | 2 |
| | (130 | ) | | (13 | ) |
Other, net | 30 |
| | (3 | ) | | 10 |
|
Net cash flows from investing activities | (2,308 | ) | | (1,909 | ) | | (1,617 | ) |
| | | | | |
Net cash flows from financing activities: | | | | | |
Proceeds from long-term debt | 687 |
| | 990 |
| | 62 |
|
Repayments of long-term debt | (350 | ) | | (255 | ) | | (38 | ) |
Net change in amounts receivable from/payable to affiliates | (8 | ) | | 133 |
| | 9 |
|
Net proceeds from (repayments of) short-term debt | 240 |
| | (99 | ) | | 99 |
|
Other, net | — |
| | — |
| | 1 |
|
Net cash flows from financing activities | 569 |
| | 769 |
| | 133 |
|
| | | | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (225 | ) | | 255 |
| | (78 | ) |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of year | 282 |
| | 27 |
| | 105 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of year | $ | 57 |
| | $ | 282 |
| | $ | 27 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MHC INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
(1) | Organization and Operations
|
MHC Inc. ("MHC") is an Iowa corporation with MidAmerican Funding, LLC ("MidAmerican Funding") as its sole shareholder. MidAmerican Funding is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MHC constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations. Direct wholly owned nonregulated subsidiaries of MHC are Midwest Capital Group, Inc. and MEC Construction Services Co.
| |
(2) | Summary of Significant Accounting Policies
|
In addition to the following significant accounting policies, refer to Note 2 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for significant accounting policies of MHC.
Basis ofConsolidation and Presentation
The Consolidated Financial Statements include the accounts of MHC and its subsidiaries in which it held a controlling financial interest as of the date of the financial statement. Intercompany accounts and transactions have been eliminated, other than those between rate-regulated operations. MHC has evaluated subsequent events through February 22, 2019, which is the date the Consolidated Financial Statements were issued.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired when MidAmerican Funding purchased MHC. MHC evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, MHC estimates the fair value of the reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MHC uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings and regulatory asset value; and an appropriate discount rate. In estimating future cash flows, MHC incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During 2018, 2017 and 2016, MHC did not record any goodwill impairments.
(3) Property, Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's property, plant and equipment, net, MHC had gross nonregulated property of $24 million as of December 31, 2018 and 2017, and related accumulated depreciation and amortization of $12 million and $10 million as of December 31, 2018 and 2017, respectively, which consisted primarily of a corporate aircraft owned by MHC.
(4)Jointly Owned Utility Facilities
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
(5)Regulatory Matters
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
| |
(6) | Investments and Restricted Investments |
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's investments and restricted investments, MHC had corporate-owned life insurance policies in a Rabbi trust owned by MHC with a total cash surrender value of $2 million as of December 31, 2018 and 2017.
(7)Short-Term Debt and Credit Facilities
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's credit facilities, MHC has a $4 million unsecured credit facility, which expires in June 2019 and has a variable interest rate based on the Eurodollar rate plus a spread. As of December 31, 2018 and 2017, there were no borrowings outstanding under this credit facility. As of December 31, 2018, MHC was in compliance with the covenants of its credit facility.
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
Tax Cuts and Jobs Act
The Tax Cuts and Jobs Act enacted on December 22, 2017 (the "2017 Tax Reform") impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018 and limitations on bonus depreciation for utility property. Accounting principles generally accepted in the United States of America ("GAAP") require the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, MHC reduced deferred income tax liabilities $1,822 million. As it is probable the change in deferred taxes for MHC's regulated businesses will be passed back to customers through regulatory mechanisms, MHC increased net regulatory liabilities by $1,845 million.
In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. On December 31, 2017, MHC recorded the impacts of 2017 Tax Reform and believed all the impacts to be complete with the exception of interpretations of the bonus depreciation rules. MHC determined the amounts recorded and the interpretations relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. MHC believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, MHC recorded a current tax benefit of $27 million and a deferred tax expense of $28 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform, MHC reduced the associated deferred income tax liabilities $12 million and increased regulatory liabilities by the same amount.
MHC's income tax benefit from continuing operations consists of the following for the years ended December 31 (in millions):
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Current: | | | | | |
Federal | $ | (277 | ) | | $ | (489 | ) | | $ | (478 | ) |
State | (12 | ) | | (25 | ) | | (14 | ) |
| (289 | ) | | (514 | ) | | (492 | ) |
Deferred: | | | | | |
Federal | 42 |
| | 338 |
| | 367 |
|
State | (9 | ) | | (3 | ) | | (4 | ) |
| 33 |
| | 335 |
| | 363 |
|
| | | | | |
Investment tax credits | (1 | ) | | (1 | ) | | (1 | ) |
Total | $ | (257 | ) | | $ | (180 | ) | | $ | (130 | ) |
Iowa Senate File 2417
In May 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% and eliminates corporate federal deductibility, both for tax years starting in 2021. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of Iowa Senate File 2417, MHC reduced net deferred income tax liabilities $54 million and decreased deferred income tax benefit by $2 million. As it is probable the change in deferred taxes for MidAmerican Energy will be passed back to customers through regulatory mechanisms, MHC increased net regulatory liabilities by $56 million.
A reconciliation of the federal statutory income tax rate to MHC's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows for the years ended December 31:
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Federal statutory income tax rate | 21 | % | | 35 | % | | 35 | % |
Income tax credits | (73 | ) | | (68 | ) | | (60 | ) |
State income tax, net of federal income tax benefit | (4 | ) | | (4 | ) | | (3 | ) |
Effects of ratemaking | (5 | ) | | (7 | ) | | (3 | ) |
2017 Tax Reform | 1 |
| | 2 |
| | — |
|
Other, net | (1 | ) | | (1 | ) | | — |
|
Effective income tax rate | (61 | )% | | (43 | )% | | (31 | )% |
Income tax credits relate primarily to production tax credits earned by MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
MHC's net deferred income tax liability consists of the following as of December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
Deferred income tax assets: | | | |
Regulatory liabilities | $ | 405 |
| | $ | 443 |
|
Asset retirement obligations | 164 |
| | 160 |
|
Employee benefits | 47 |
| | 45 |
|
Other | 85 |
| | 62 |
|
Total deferred income tax assets | 701 |
| | 710 |
|
| | | |
Deferred income tax liabilities: | | | |
Depreciable property | (2,947 | ) | | (2,868 | ) |
Regulatory assets | (62 | ) | | (42 | ) |
Other | (11 | ) | | (35 | ) |
Total deferred income tax liabilities | (3,020 | ) | | (2,945 | ) |
| | | |
Net deferred income tax liability | $ | (2,319 | ) | | $ | (2,235 | ) |
As of December 31, 2018, MHC has available $44 million of state tax carryforwards, principally related to $655 million of net operating losses, that expire at various intervals between 2019 and 2037.
The United States Internal Revenue Service has closed its examination of MHC's income tax returns through December 31, 2011. The statute of limitations for MHC's state income tax returns have expired through December 31, 2009, with the exception of Iowa and Illinois, for which the statute of limitations have expired through December 31, 2014, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
A reconciliation of the beginning and ending balances of MHC's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Beginning balance | $ | 12 |
| | $ | 10 |
|
Additions based on tax positions related to the current year | 4 |
| | 1 |
|
Additions for tax positions of prior years | 47 |
| | 23 |
|
Reductions based on tax positions related to the current year | (4 | ) | | (4 | ) |
Reductions for tax positions of prior years | (48 | ) | | (19 | ) |
Interest and penalties | (1 | ) | | 1 |
|
Ending balance | $ | 10 |
| | $ | 12 |
|
As of December 31, 2018, MHC had unrecognized tax benefits totaling $30 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MHC's effective income tax rate.
| |
(10) | Employee Benefit Plans |
Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding MHC's pension, supplemental retirement and postretirement benefit plans.
Pension and postretirement costs allocated by MHC to its parent and other affiliates in each of the years ended December 31, were as follows (in millions):
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Pension costs | $ | 3 |
| | $ | 4 |
| | $ | 4 |
|
Other postretirement costs | (2 | ) | | (3 | ) | | (1 | ) |
| |
(11) | Asset Retirement Obligations |
Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
| |
(12) | Fair Value Measurements |
Refer to Note 12 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
| |
(13) | Commitments and Contingencies |
Refer to Note 13 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
Legal Matters
MHC is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MHC does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
| |
(14) | Components of Accumulated Other Comprehensive Loss, Net |
Refer to Note 14 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.
(15) Revenue from Contracts with Customers
Refer to Note 15 of MidAmerican Energy's Notes to Financial Statements. Additionally, MHC had $4 million of other revenue from contracts with customers for the year ended December 31, 2018.
(16)Other Income (Expense) - Other, Net
Other, net, as shown on the Consolidated Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| | | | | |
Non-service cost components of postretirement employee benefit plans | $ | 21 |
| | $ | 18 |
| | $ | 15 |
|
Corporate-owned life insurance income | 6 |
| | 13 |
| | 8 |
|
Gain on redemption of auction rate securities | — |
| | — |
| | 5 |
|
Gains on sales of assets and other investments | 1 |
| | 1 |
| | 3 |
|
Interest income and other, net | 3 |
| | 7 |
| | 2 |
|
Total | $ | 31 |
| | $ | 39 |
| | $ | 33 |
|
(17)Supplemental Cash Flow Information
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2018 and 2017, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2018 and 2017 as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
|
| | | | | | | |
| As of December 31, |
| 2018 | | 2017 |
| | | |
Cash and cash equivalents | $ | 1 |
| | $ | 172 |
|
Restricted cash and cash equivalents in other current assets | 56 |
| | 110 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 57 |
| | $ | 282 |
|
The summary of supplemental cash flow information as of and for the years ending December 31 is as follows (in millions):
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Supplemental cash flow information: | | | | | |
Interest paid, net of amounts capitalized | $ | 201 |
| | $ | 193 |
| | $ | 181 |
|
Income taxes received, net | $ | 494 |
| | $ | 463 |
| | $ | 600 |
|
| | | | | |
Supplemental disclosure of non-cash investing and financing transactions: | | | | | |
Accounts payable related to utility plant additions | $ | 371 |
| | $ | 224 |
| | $ | 131 |
|
Transfer of unregulated retail services business to affiliate | $ | — |
| | $ | — |
| | $ | 90 |
|
| |
(18) | Related Party Transactions |
The companies identified as affiliates of MHC are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in service agreements between MHC and the affiliates.
MHC is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for allocated general costs, such as insurance and building rent, and for employee wages, benefits and costs for corporate functions, such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $44 million, $46 million and $35 million for 2018, 2017 and 2016, respectively. Additionally, in 2018, MHC received $15 million from BHE for the transfer of corporate aircraft.
MHC reimbursed BHE in the amount of $11 million, $7 million and $6 million in 2018, 2017 and 2016, respectively, for its share of corporate expenses.
MidAmerican Energy purchases natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE, and coal transportation services from BNSF Railway Company, a wholly owned subsidiary of Berkshire Hathaway, in the normal course of business at either tariffed or market prices. These purchases totaled $127 million, $122 million and $135 million in 2018, 2017 and 2016, respectively.
MHC has a $300 million revolving credit arrangement carrying interest at the 30-day LIBOR rate plus a spread to borrow from BHE. Outstanding balances are unsecured and due on demand. The outstanding balance was $156 million at an interest rate of 2.629% as of December 31, 2018, and $164 million at an interest rate of 1.629% as of December 31, 2017, and is reflected as note payable to affiliate on the Consolidated Balance Sheet.
BHE has a $100 million revolving credit arrangement carrying interest at the 30-day LIBOR rate plus a spread to borrow from MHC. Outstanding balances are unsecured and due on demand. There were no borrowings outstanding throughout 2018 and 2017.
MHC pays all obligations of and receives all payments to MidAmerican Funding, including primarily interest costs on MidAmerican Funding's long-term debt and income taxes. Additionally, in 2017, MHC paid for MidAmerican Funding's redemption of a portion of its long-term debt through a tender offer. On behalf of MidAmerican Funding, MHC received a net amount of $2 million in 2018 and paid net amounts of $130 million and $13 million for 2017 and 2016, respectively.
MHC had accounts receivable from affiliates of $433 million and $438 million as of December 31, 2018 and 2017, respectively, that are reflected in receivables, net and receivable from affiliate on the Consolidated Balance Sheets. MHC also had accounts payable to affiliates of $12 million and $14 million as of December 31, 2018 and 2017, respectively, that are included in accounts payable on the Consolidated Balance Sheets.
MHC is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, MHC had a payable to BHE of $156 million as of December 31, 2018, and a receivable from BHE of $51 million as of December 31, 2017. MHC received net cash receipts for federal and state income taxes from BHE totaling $494 million, $463 million and $600 million for the years ended December 31, 2018, 2017 and 2016, respectively.
MHC recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MHC's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates. MHC adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $20 million and $16 million as of December 31, 2018 and 2017, respectively, and similar amounts payable to affiliates totaled $36 million and $45 million, as of December 31, 2018 and 2017, respectively. See Note 10 for further information pertaining to pension and postretirement accounting.
MHC has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists principally of the nonregulated subsidiaries of MHC not engaged in the energy business. Refer to Note 9 for a discussion of items affecting income tax (benefit) expense for the regulated electric and natural gas operating segments.
The following tables provide information on a reportable segment basis (in millions):
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenue: | | | | | |
Regulated electric | $ | 2,283 |
| | $ | 2,108 |
| | $ | 1,985 |
|
Regulated natural gas | 754 |
| | 719 |
| | 637 |
|
Other | 16 |
| | 19 |
| | 9 |
|
Total operating revenue | $ | 3,053 |
| | $ | 2,846 |
| | $ | 2,631 |
|
| | | | | |
Depreciation and amortization: | | | | | |
Regulated electric | $ | 565 |
| | $ | 458 |
| | $ | 436 |
|
Regulated natural gas | 44 |
| | 42 |
| | 43 |
|
Total depreciation and amortization | $ | 609 |
| | $ | 500 |
| | $ | 479 |
|
| | | | | |
Operating income: | | | | | |
Regulated electric | $ | 469 |
| | $ | 472 |
| | $ | 486 |
|
Regulated natural gas | 81 |
| | 72 |
| | 64 |
|
Other | — |
| | — |
| | 1 |
|
Total operating income | $ | 550 |
| | $ | 544 |
| | $ | 551 |
|
| | | | | |
Interest expense: | | | | | |
Regulated electric | $ | 208 |
| | $ | 196 |
| | $ | 178 |
|
Regulated natural gas | 19 |
| | 18 |
| | 18 |
|
Other | 4 |
| | 1 |
| | — |
|
Total interest expense | $ | 231 |
| | $ | 215 |
| | $ | 196 |
|
| | | | | |
Income tax (benefit) expense: | | | | | |
Regulated electric | $ | (273 | ) | | $ | (212 | ) | | $ | (156 | ) |
Regulated natural gas | 16 |
| | 29 |
| | 22 |
|
Other | — |
| | 3 |
| | 4 |
|
Total income tax (benefit) expense | $ | (257 | ) | | $ | (180 | ) | | $ | (130 | ) |
| | | | | |
Net income: | | | | | |
Regulated electric | $ | 628 |
| | $ | 570 |
| | $ | 512 |
|
Regulated natural gas | 54 |
| | 35 |
| | 32 |
|
Other | (2 | ) | | (1 | ) | | 1 |
|
Net income | $ | 680 |
| | $ | 604 |
| | $ | 545 |
|
| | | | | |
Capital expenditures: | | | | | |
Regulated electric | $ | 2,223 |
| | $ | 1,686 |
| | $ | 1,564 |
|
Regulated natural gas | 109 |
| | 87 |
| | 72 |
|
Total capital expenditures | $ | 2,332 |
| | $ | 1,773 |
| | $ | 1,636 |
|
|
| | | | | | | | | | | |
| As of December 31, |
| 2018 | | 2017 | | 2016 |
Total assets: | | | | | |
Regulated electric | $ | 17,702 |
| | $ | 16,105 |
| | $ | 15,304 |
|
Regulated natural gas | 1,485 |
| | 1,482 |
| | 1,424 |
|
Other | 443 |
| | 451 |
| | 317 |
|
Total assets | $ | 19,630 |
| | $ | 18,038 |
| | $ | 17,045 |
|
Goodwill by reportable segment as of December 31, 2018 and 2017 was as follows (in millions):
|
| | | |
Regulated electric | $ | 1,191 |
|
Regulated natural gas | 79 |
|
Total | $ | 1,270 |
|
EXHIBIT INDEX
BERKSHIRE HATHAWAY ENERGY
| |
Exhibit No.4.10 | Description
|
| | | | | |
4.12Exhibit No. | Description |
| |
4.23 | First Supplemental Trust Deed, dated as of September 27, 2001, among Northern Electric Finance plc, Northern Electric plc, Northern Electric Distribution Limited and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.81 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004). |
| | | | | |
4.29Exhibit No. | Description |
| |
Exhibit No.4.30 | Description
|
| |
4.434.37 | Fiscal Agency Agreement,Trust Deed, dated as of July 15, 2008, byMay 24, 2019, among Northern Electric Finance plc, Northern Powergrid (Northeast) Limited, and between Northern Natural GasHSBC Corporate Trustee Company and The Bank New York Mellon Trust Company, National Association, Fiscal Agent,(UK) Limited, relating to the $200,000,000£150,000,000 in principal amount of the 5.75% Senior Notes2.75% Guaranteed Bonds due 20182049 (incorporated by reference to Exhibit 4.324.1 to the Berkshire Hathaway Energy Company AnnualQuarterly Report on Form 10-K10-Q for the yearquarter ended December 31, 2008)June 30, 2019). |
| |
4.444.38 | Fiscal Agency Agreement,Trust Deed, dated as of April 20, 2011, byOctober 9, 2019, among Northern Powergrid (Yorkshire) plc and between Northern Natural GasHSBC Corporate Trustee Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent,(UK) Limited, relating to the $200,000,000£300,000,000 in principal amount of the 4.25% Senior Notes2.25% Guaranteed Bonds due 20212059 (incorporated by reference to Exhibit 4.274.3 to the Berkshire Hathaway Energy Company AnnualQuarterly Report on Form 10-K10-Q for the yearquarter ended December 31, 2011)September 30, 2019). |
| |
4.474.42 | Fiscal Agency Agreement, dated as of July 12,17, 2018, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $450,000,000 in principal amount of the 4.30% Senior Bonds due 2049 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).. |
| | | | | |
4.59Exhibit No. | Description |
| |
Exhibit No.4.56 | Description
|
| |
4.654.60 | Twenty-Third Supplemental Indenture, dated as of September 11, 2020, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada, as trustee, relating to the C$225,000,000 in principal amount of the 1.509% Series 2020-1 Senior Secured Notes due 2030 (incorporated by reference to Exhibit 4.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2020). |
| |
4.61 | |
| |
4.664.62 | First Supplemental Indenture, dated as of April 15, 2013, between Topaz Solar Farms LLC, as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the $250,000,000 in principal amount of the 4.875% Series B Senior Secured Notes due 2039 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). |
| |
4.674.63 | Indenture, dated as of June 27, 2013, between Solar Star Funding, LLC, as Issuer, and Wells Fargo Bank, National Association, as Trustee, relating to the $1,000,000,000 in principal amount of the 5.375% Series A Senior Secured Notes due 2035 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). |
| |
4.684.64 | First Supplemental Indenture, dated as of March 12, 2015, between Solar Star Funding, LLC, as Issuer, and Wells Fargo Bank, National Association, as Trustee, relating to the $325,000,000 in principal amount of the 3.95% Series B Senior Secured Notes due 2035 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2015). |
| |
10.1 | $3,500,000,000 Second Amended and Restated Credit Agreement, dated as of AprilJune 30, 2018,2021, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018)June 30, 2021). |
| |
10.2 | Amended and Restated £150,000,000£200,000,000 Facility Agreement, dated April 30, 2015,as of December 22, 2021, among Northern Powergrid Holdings Company, as Guarantor, and Borrower, Northern Powergrid (Yorkshire) plc and Northern Powergrid (Northeast) Limited, as Borrowers, and Abbey National Treasury ServicesSantander UK plc, Lloyds Bank plc and The RoyalNational Westminster Bank of Scotland plc, as Original Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).Lenders. |
| |
| | | | | |
10.3 | Amended and Restated Credit Agreement, dated as of July 30, 2015,January 24, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company QuarterlyAnnual Report on Form 10-Q10-K for the quarteryear ended June 30, 2016)December 31, 2019). |
| |
10.4 | First Third Amending Agreement to the Amended and Restated Credit Agreement, dated as of November 20, 2015,December 15, 2021, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders. |
| |
10.5 | Fourth Amended and Restated Credit Agreement, dated as of January 24, 2020, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.5 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2019). |
| |
10.6 | |
| |
10.7 | Fifth Amended and Restated Credit Agreement, dated as of January 24, 2020, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.4 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2019). |
| |
10.8 | |
| |
10.9 | Credit Agreement, dated as of April 27, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.410.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016)2020). |
| |
Exhibit No.10.10 | Description
|
| |
10.5 | Second Amending Agreement to Amended and Restated Credit Agreement, dated as of December 14, 2015, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016). |
| |
10.6 | Third Amending Agreement to Amended and Restated Credit Agreement, dated as of July 8, 2016, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.6 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016). |
| |
10.7 | Fourth Amending Agreement to Amended and Restated Credit Agreement, dated as of December 15, 2016, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.7 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2016). |
| |
10.8 | Fifth Amending Agreement to Amended and Restated Credit Agreement, dated as of December 15, 2017, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.9 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2017). |
| |
10.9 | Sixth Amending Agreement to Amended and Restated Credit Agreement, dated as of December 14, 2018, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders. |
| |
10.10 | Fourth Amended and Restated Credit Agreement, dated as of December 17, 2015, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.8 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016). |
| |
10.11 | First Amending Agreement to Fourth Amended and Restated Credit Agreement, dated as of December 15, 2016, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.10 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2016). |
| |
10.12 | Second Amending Agreement to Fourth Amended and Restated Credit Agreement, dated as of December 14, 2017, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.14 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2017). |
| |
10.13 | Third Amending Agreement to Fourth Amended and Restated Credit Agreement, dated as of April 19, 2018, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018) |
| |
10.14 | Fourth Amending Agreement to Fourth Amended and Restated Credit Agreement, dated as of December 14, 2018, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders. |
| |
10.15 | Third Amended and Restated Credit Agreement, dated as of December 17, 2015, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.7 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016). |
| |
10.16 | First Amending Agreement to Third Amended and Restated Credit Agreement, dated as of December 15, 2016, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.12 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2016). |
| |
10.17 | Second Amending Agreement to Third Amended and Restated Credit Agreement, dated as of December 14, 2017, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.17 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2017). |
| |
10.18 | Third Amending Agreement to Third Amended and Restated Credit Agreement, dated as of April 19, 2018, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018) |
| |
10.19 | Fourth Amending Agreement to Third Amended and Restated Credit Agreement, dated as of December 14, 2018, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders. |
PACIFICORP
| | | | | |
| |
Exhibit No.10.15* | Description
|
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
| | | | | | | | | | | | | | | | | |
4.694.65 | Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, incorporated by reference to Exhibit 4-E to the PacifiCorp Form 8-B, as supplemented and modified by 2931 Supplemental Indentures, each incorporated by reference, as follows: |
|
| | | | |
Exhibit | | PacifiCorp | | |
Number | Exhibit Number | | PacifiCorp File Type | | File Date |
| (4)(b)(a) | | SE | | November 2, 1989 |
| (4)(a)(a) | | 8-K | | January 9, 1990 |
| (4)(a)(a) | | 8-K | | September 11, 1991 |
| (4)(a)(a) | | 8-K | | January 7, 1992 |
| (4)(a)(a) | | 10-Q | | Quarter ended March 31, 1992 |
| (4)(a)(a) | | 10-Q | | Quarter ended September 30, 1992 |
| (4)(a)(a) | | 8-K | | April 1, 1993 |
| (4)(a)(a) | | 10-Q | | Quarter ended September 30, 1993 |
| | | 10-Q | | Quarter ended June 30, 1994 |
| | | 10-K | | Year ended December 31, 1994 |
| | | 10-K | | Year ended December 31, 1995 |
| | | 10-K | | Year ended December 31, 1996 |
| | | 10-K | | Year ended December 31, 1998 |
| | | 8-K | | November 21, 2001 |
| | | 10-Q | | Quarter ended June 30, 2003 |
| | | 8-K | | September 9, 2003 |
| | | 8-K | | August 26, 2004 |
| | | 8-K | | June 14, 2005 |
| | | 8-K | | August 14, 2006 |
| | | 8-K | | March 14, 2007 |
| | | 8-K | | October 3, 2007 |
| | | 8-K | | July 17, 2008 |
| | | 8-K | | January 8, 2009 |
| | | 8-K | | May 12, 2011 |
| | | 8-K | | January 6, 2012 |
| | | 8-K | | June 6, 2013 |
| | | 8-K | | March 13, 2014 |
| | | 8-K | | June 19, 2015 |
| | | 8-K | | July 13, 2018 |
| | | 8-K | | March 1, 2019 |
10.31 | | | 8-K | | April 8, 2020 |
| | | 8-K | | July 9, 2021 |
10.20 | $600,000,0001,200,000,000 Second Amended and Restated Credit Agreement dated as of AprilJune 30, 2018,2021, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorganJP Morgan Chase Bank, N.A., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.410.2 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended March 31, 2018)June 30, 2021). |
| |
10.3295 | $600,000,000 Amended and Restated Credit Agreement, dated as of April 30, 2018, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, and the LC Issuing Banks (incorporated by reference to Exhibit 10.5 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended March 31, 2018) |
MIDAMERICAN ENERGY
MIDAMERICAN FUNDING
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING
| |
Exhibit No.4.84 | Description
|
| | | | | |
4.94Exhibit No. | Description |
| |
4.994.93 | |
| |
4.94 | |
| |
4.95 | |
| |
4.96 | |
| |
4.97 | |
| |
4.98 | |
| |
4.1004.99 | Intercreditor and Collateral Trust Agreement, dated as of September 9, 2013, among MidAmerican Energy Company, The Bank of New York Mellon Trust Company, N.A., as trustee, and The Bank of New York Mellon Trust Company, N.A., as collateral trustee (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated September 13, 2013). |
| |
10.3310.21 | $900,000,0001,500,000,000 Second Amended and Restated Credit Agreement, dated as of AprilJune 30, 2018,2021, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, LTD.Ltd., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.610.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018)June 30, 2021). |
BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN FUNDING
NEVADA POWER
| | | | | |
Exhibit No.3.12 | Description
|
NEVADA POWER
| |
14.510.23 | $300,000,000 Delayed Draw Term Loan Agreement, dated as of January 14, 2022, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, U.S. Bank National Association, as Administrative Agent and U.S. Bank National Association and Sumitomo Mitsui Banking Corporation, as Joint Lead Arrangers and Joint Bookrunners. |
| |
14.5 | |
BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
| |
Exhibit No.4.110 | Description
|
| |
10.354.114 | |
| |
4.115 | |
| |
10.24 | $400,000,000 ThirdFourth Amended and Restated Credit Agreement, dated as of AprilJune 30, 2018,2021, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.710.4 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018)June 30, 2021). |
SIERRA PACIFIC
| | | | | |
4.121Exhibit No. | Description |
| |
Exhibit No.10.25 | Description
|
BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
| |
10.3710.26 | $250,000,000 ThirdFourth Amended and Restated Credit Agreement, dated as of AprilJune 30, 2018,2021, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.810.5 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018)June 30, 2021). |
EASTERN ENERGY GAS
ALL REGISTRANTS
| | | | | |
10.27 | |
| |
10.28 | |
| |
31.13 | |
| |
31.14 | |
| |
32.13 | |
| |
32.14 | |
BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS
| | | | | |
4.125 | |
| |
4.126 | |
| |
4.127 | Third Supplemental Indenture, dated as of October 1, 2013, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 4.80% Senior Notes due 2043 (incorporated by reference to Exhibit 4.4, Form S-4, File No. 333-195066, dated April 4, 2014). |
| |
4.128 | |
| |
4.129 | |
| |
4.130 | |
| |
4.131 | |
| |
4.132 | |
| |
4.133 | |
| |
4.134 | |
| |
4.135 | |
| |
| | | | | |
4.136 | |
| |
4.137 | Fifteenth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as trustee, to the Indenture dated as of October 1, 2013, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated July 1, 2021). |
| |
4.138 | |
| |
4.139 | |
| |
4.140 | First Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.900% Senior Notes due 2049 (incorporated by reference to Exhibit 4.7 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
| |
4.141 | Second Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.600% Senior Notes due 2044 (incorporated by reference to Exhibit 4.8 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
| |
4.142 | Third Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.800% Senior Notes due 2043 (incorporated by reference to Exhibit 4.9 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
| |
4.143 | Fourth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.000% Senior Notes due 2029 (incorporated by reference to Exhibit 4.10 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
| |
4.144 | Fifth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.600% Senior Notes due 2024 (incorporated by reference to Exhibit 4.11 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
| |
10.29 | |
ALL REGISTRANTS
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101 | The following financial information from each respective Registrant's Annual Report on Form 10-K for the year ended December 31, 20182021 is formatted in XBRL (eXtensibleiXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail. |
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104 | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. |
(a) Not available electronically on the SEC website as it was filed in paper previous to the electronic system currently in place.
* Management contract or compensatory plan.
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, each Registrant has not filed as an exhibit to this Form 10-K certain instruments with respect to long-term debt not registered in which the total amount of securities authorized thereunder does not exceed 10% of the total assets of the respective Registrant. Each Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.
SIGNATURES
BERKSHIRE HATHAWAY ENERGY COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 22nd25th day of February 2019.
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| BERKSHIRE HATHAWAY ENERGY COMPANY |
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| BERKSHIRE HATHAWAY ENERGY COMPANY |
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| /s/ William J. Fehrman* |
| William J. Fehrman |
| Director, President and Chief Executive Officer |
| (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Signature | | Title | | Date |
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/s/ William J. Fehrman* | | Director, President and Chief Executive Officer | | February 25, 2022 |
William J. Fehrman | | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ William J. Fehrman*Calvin D. Haack* | | Director, President and Chief Executive Officer | | February 22, 2019 |
William J. Fehrman | | (principal executive officer) | | |
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/s/ Patrick J. Goodman* | | ExecutiveSenior Vice President and Chief Financial Officer | | February 22, 201925, 2022 |
Patrick J. GoodmanCalvin D. Haack | | (principal financial and accounting officer) | | |
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/s/ Gregory E. Abel* | | Executive ChairmanChair of the Board of Directors | | February 22, 201925, 2022 |
Gregory E. Abel | | of Directors | | |
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/s/ Warren E. Buffett* | | Director | | February 22, 201925, 2022 |
Warren E. Buffett | | | | |
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/s/ Marc D. Hamburg* | | Director | | February 22, 201925, 2022 |
Marc D. Hamburg | | | | |
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/s/ Walter Scott, Jr.* | | Director | | February 22, 2019 |
Walter Scott, Jr. | | | | |
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*By: /s/ Natalie L. Hocken | | Attorney-in-Fact | | February 22, 201925, 2022 |
Natalie L. Hocken | | | | |
SIGNATURES
PACIFICORP
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 22nd25th day of February 2019.
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| PACIFICORP |
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| PACIFICORP |
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| /s/ Nikki L. Kobliha |
| Nikki L. Kobliha |
| Director, Vice President, Chief Financial Officer and |
| Treasurer |
| (principal financial and accounting officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Signature | | Title | | Date |
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/s/ William J. Fehrman | | Chair of the Board of Directors and Chief Executive | | February 25, 2022 |
William J. Fehrman | | Officer | | |
| | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ William J. Fehrman | | Chairman of the Board of Directors and Chief | | February 22, 2019 |
William J. Fehrman | | Executive Officer | | |
| | (principal executive officer) | | |
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/s/ Nikki L. Kobliha | | Director, Vice President, Chief Financial Officer and | | February 22, 201925, 2022 |
Nikki L. Kobliha | | Treasurer | | |
| | (principal financial and accounting officer) | | |
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/s/ Stefan A. Bird | | Director | | February 22, 201925, 2022 |
Stefan A. Bird | | | | |
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/s/ Patrick J. GoodmanCalvin D. Haack | | Director | | February 22, 201925, 2022 |
Patrick J. GoodmanCalvin D. Haack | | | | |
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/s/ Natalie L. Hocken | | Director | | February 22, 201925, 2022 |
Natalie L. Hocken | | | | |
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/s/ Gary W. Hoogeveen | | Director | | February 22, 201925, 2022 |
Gary W. Hoogeveen | | | | |
SIGNATURES
MIDAMERICAN ENERGY COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 22nd25th day of February 2019.
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| MIDAMERICAN ENERGY COMPANY |
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| MIDAMERICAN ENERGY COMPANY/s/ Kelcey A. Brown |
| Kelcey A. Brown |
| /s/ Adam L. Wright |
| Adam L. Wright |
| Director, President and Chief Executive Officer |
| (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
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Signature | | Title | | Date |
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/s/ Kelcey A. Brown | | Director, President and Chief Executive Officer | | February 25, 2022 |
Kelcey A. Brown | | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ Adam L. Wright | | Director, President and Chief Executive Officer | | February 22, 2019 |
Adam L. Wright | | (principal executive officer) | | |
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/s/ Thomas B. Specketer | | Director, Vice President and Chief Financial Officer | | February 22, 201925, 2022 |
Thomas B. Specketer | | (principal financial and accounting officer) | | |
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/s/ Robert B. Berntsen | | Director | | February 22, 2019 |
Robert B. Berntsen | | | | |
SIGNATURES
MIDAMERICAN FUNDING, LLC
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 22nd25th day of February 2019.
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| MIDAMERICAN FUNDING, LLC |
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| MIDAMERICAN FUNDING, LLC/s/ Kelcey A. Brown |
| Kelcey A. Brown |
| /s/ Adam L. Wright |
| Adam L. Wright |
| Manager and President |
| (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
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Signature | | Title | | Date |
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/s/ Kelcey A. Brown | | Manager and President | | February 25, 2022 |
Kelcey A. Brown | | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ Adam L. Wright | | Manager and President | | February 22, 2019 |
Adam L. Wright | | (principal executive officer) | | |
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/s/ Thomas B. Specketer | | Vice President and Controller | | February 22, 201925, 2022 |
Thomas B. Specketer | | (principal financial and accounting officer) | | |
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/s/ Daniel S. Fick | | Manager | | February 22, 201925, 2022 |
Daniel S. Fick | | | | |
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/s/ Patrick J. GoodmanCalvin D. Haack | | Manager | | February 22, 201925, 2022 |
Patrick J. GoodmanCalvin D. Haack | | | | |
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/s/ Natalie L. Hocken | | Manager | | February 22, 201925, 2022 |
Natalie L. Hocken | | | | |
SIGNATURES
NEVADA POWER COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 22nd25th day of February 2019.
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| NEVADA POWER COMPANY |
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| /s/ Douglas A. Cannon |
| Douglas A. Cannon |
| Director, President and Chief Executive Officer |
| (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
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Signature | | Title | | Date |
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/s/ Douglas A. Cannon | | Director, President and Chief Executive Officer | | February 25, 2022 |
Douglas A. Cannon | | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ Douglas A. Cannon | | Director, President and Chief Executive Officer | | February 22, 2019 |
Douglas A. Cannon | | (principal executive officer) | | |
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/s/ Michael E. Cole | | Director, Vice President, and Chief Financial Officer and Treasurer | | February 22, 201925, 2022 |
Michael E. Cole | | Financial Officer | | |
| | (principal financial and accounting officer) | | |
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/s/ ShawnBrandon M. EliceguiBarkhuff | | Director | | February 22, 201925, 2022 |
ShawnBrandon M. EliceguiBarkhuff | | | | |
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/s/ Jennifer L. Oswald | | Director | | February 25, 2022 |
Jennifer L. Oswald | | | | |
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/s/ Anthony F. Sanchez, III | | Director | | February 22, 201925, 2022 |
Anthony F. Sanchez, III | | | | |
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/s/ Kevin C. Geraghty | | Director | | February 22, 2019 |
Kevin C. Geraghty | | | | |
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/s/ Jennifer L. Oswald | | Director | | February 22, 2019 |
Jennifer L. Oswald | | | | |
SIGNATURES
SIERRA PACIFIC POWER COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 22nd25th day of February 2019.
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| SIERRA PACIFIC POWER COMPANY |
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| /s/ Douglas A. Cannon |
| Douglas A. Cannon |
| Director, President and Chief Executive Officer |
| (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
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Signature | | Title | | Date |
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/s/ Douglas A. Cannon | | Director, President and Chief Executive Officer | | February 25, 2022 |
Douglas A. Cannon | | (principal executive officer) | | |
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Signature | | Title | | Date |
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/s/ Douglas A. Cannon | | Director, President and Chief Executive Officer | | February 22, 2019 |
Douglas A. Cannon | | (principal executive officer) | | |
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/s/ Michael E. Cole | | Director, Vice President, and Chief Financial Officer and Treasurer | | February 22, 201925, 2022 |
Michael E. Cole | | Financial Officer | | |
| | (principal financial and accounting officer) | | |
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/s/ ShawnBrandon M. EliceguiBarkhuff | | Director | | February 22, 201925, 2022 |
ShawnBrandon M. EliceguiBarkhuff | | | | |
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/s/ Jennifer L. Oswald | | Director | | February 25, 2022 |
Jennifer L. Oswald | | | | |
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/s/ Anthony F. Sanchez, III | | Director | | February 22, 201925, 2022 |
Anthony F. Sanchez, III | | | | |
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/s/ Kevin C. Geraghty | | Director | | February 22, 2019 |
Kevin C. Geraghty | | | | |
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/s/ Jennifer L. Oswald | | Director | | February 22, 2019 |
Jennifer L. Oswald | | | | |
SIGNATURES
EASTERN ENERGY GAS HOLDINGS, LLC
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 25th day of February 2022.
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| EASTERN ENERGY GAS HOLDINGS, LLC |
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| /s/ Paul E. Ruppert |
| Paul E. Ruppert |
| President and Chief Executive Officer |
| (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
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Signature | | Title | | Date |
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/s/ Paul E. Ruppert | | President and Chief Executive Officer | | February 25, 2022 |
Paul E. Ruppert | | (principal executive officer) | | |
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/s/ Scott C. Miller | | Vice President, Chief Financial Officer and Treasurer | | February 25, 2022 |
Scott C. Miller | | (principal financial officer) | | |
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/s/ Mark A. Hewett | | Manager | | February 25, 2022 |
Mark A. Hewett | | | | |
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/s/ Calvin D. Haack | | Manager | | February 25, 2022 |
Calvin D. Haack | | | | |
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/s/ Natalie L. Hocken | | Manager | | February 25, 2022 |
Natalie L. Hocken | | | | |
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
No annual report to security holders covering each respective Registrant's last fiscal year or proxy material has been sent to security holders.