0001081316us-gaap:AccumulatedOtherComprehensiveIncomeMemberbhe:PacificorpMember2020-01-012020-09-30



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X]☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2017
or
[  ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2021
or
☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Exact name of registrant as specified in its charter
State or other jurisdiction of incorporation or organization
CommissionAddress of principal executive officesIRS Employer
File NumberRegistrant's telephone number, including area codeIdentification No.
001-14881BERKSHIRE HATHAWAY ENERGY COMPANY94-2213782
(An Iowa Corporation)
666 Grand Avenue
Des Moines, Iowa 50309-2580
515-242-4300
001-05152PACIFICORP93-0246090
(An Oregon Corporation)
825 N.E. Multnomah Street, Suite 1900
Portland, Oregon 97232
888-221-7070
333-90553MIDAMERICAN FUNDING, LLC47-0819200
(An Iowa Limited Liability Company)
666 Grand Avenue
Des Moines, Iowa 50309-2580
515-242-4300
Commission
File Number
333-15387
Exact name of registrant as specified in its charter;
State or other jurisdiction of incorporation or organization
MIDAMERICAN ENERGY COMPANY
IRS Employer
Identification No.
42-1425214
001-14881BERKSHIRE HATHAWAY ENERGY COMPANY94-2213782
(An Iowa Corporation)
666 Grand Avenue Suite 500
Des Moines, Iowa 50309-2580
515-242-4300
001-05152000-52378PACIFICORP93-0246090
(An Oregon Corporation)
825 N.E. Multnomah Street
Portland, Oregon 97232
888-221-7070
333-90553MIDAMERICAN FUNDING, LLC47-0819200
(An Iowa Limited Liability Company)
666 Grand Avenue, Suite 500
Des Moines, Iowa 50309-2580
515-242-4300
333-15387MIDAMERICAN ENERGY COMPANY42-1425214
(An Iowa Corporation)
666 Grand Avenue, Suite 500
Des Moines, Iowa 50309-2580
515-242-4300
000-52378NEVADA POWER COMPANY88-0420104
(A Nevada Corporation)
6226 West Sahara Avenue
Las Vegas, Nevada 89146
702-402-5000
000-00508SIERRA PACIFIC POWER COMPANY88-0044418
(A Nevada Corporation)
6100 Neil Road
Reno, Nevada 89511
775-834-4011
001-37591N/AEASTERN ENERGY GAS HOLDINGS, LLC46-3639580
(A Virginia Limited Liability Company)
6603 West Broad Street
Richmond, Virginia 23230
804-613-5100
N/A
(Former name or former address, if changed from last report)




RegistrantSecurities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANYNone
PACIFICORPNone
MIDAMERICAN FUNDING, LLCNone
MIDAMERICAN ENERGY COMPANYNone
NEVADA POWER COMPANYNone
SIERRA PACIFIC POWER COMPANYNone
EASTERN ENERGY GAS HOLDINGS, LLCNone
RegistrantName of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANYNone
PACIFICORPNone
MIDAMERICAN FUNDING, LLCNone
MIDAMERICAN ENERGY COMPANYNone
NEVADA POWER COMPANYNone
SIERRA PACIFIC POWER COMPANYNone
EASTERN ENERGY GAS HOLDINGS, LLCNone
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
RegistrantYesNo
BERKSHIRE HATHAWAY ENERGY COMPANYX☒
PACIFICORPX☒
MIDAMERICAN FUNDING, LLCX☒
MIDAMERICAN ENERGY COMPANYX☒
NEVADA POWER COMPANYX☒
SIERRA PACIFIC POWER COMPANYX☒
EASTERN ENERGY GAS HOLDINGS, LLC☒
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
RegistrantLarge Accelerated Fileraccelerated filerAccelerated filerNon-accelerated FilerfilerSmaller Reporting Companyreporting companyEmerging Growth Companygrowth company
BERKSHIRE HATHAWAY ENERGY COMPANY☐☐X☒☐☐
PACIFICORP☐☐X☒☐☐
MIDAMERICAN FUNDING, LLC☐☐X☒☐☐
MIDAMERICAN ENERGY COMPANY☐☐X☒☐☐
NEVADA POWER COMPANY☐☐X☒☐☐
SIERRA PACIFIC POWER COMPANY☐☐X☒☐☐
EASTERN ENERGY GAS HOLDINGS, LLC☐☐☒☐☐
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o


Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  o☐  No  x
All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of October 31, 2017, 77,174,325November 4, 2021, 76,368,874 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of October 31, 2017,November 4, 2021, 357,060,915 shares of common stock, no par value, were outstanding.
All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of October 31, 2017.November 4, 2021.
All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of October 31, 2017,November 4, 2021, 70,980,203 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 31, 2017,November 4, 2021, 1,000 shares of common stock, $1.00 stated value, were outstanding.
All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of October 31, 2017,November 4, 2021, 1,000 shares of common stock, $3.75 par value, were outstanding.
All of the member's equity of Eastern Energy Gas Holdings, LLC is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of November 4, 2021.
This combined Form 10-Q is separately filed by Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, and Sierra Pacific Power Company.Company and Eastern Energy Gas Holdings, LLC. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.






TABLE OF CONTENTS
 
PART I
 
1
2
151186
151186
 
PART II
 
152187
152187
152187
152187
152188
152188
152188
153193
Exhibit Index
154



i



Definition of Abbreviations and Industry Terms


When used in Forward-Looking Statements, Part I - Items 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.
Berkshire Hathaway Energy Company and Related Entities
BHEBerkshire Hathaway Energy Company
Berkshire HathawayBerkshire Hathaway Inc.
Berkshire Hathaway Energy or the CompanyBerkshire Hathaway Energy Company and its subsidiaries
PacifiCorpPacifiCorp and its subsidiaries
MidAmerican FundingMidAmerican Funding, LLC and its subsidiaries
MidAmerican EnergyMidAmerican Energy Company
NV EnergyNV Energy, Inc. and its subsidiaries
Nevada PowerNevada Power Company and its subsidiaries
Sierra PacificSierra Pacific Power Company and its subsidiaries
Nevada UtilitiesNevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
RegistrantsEastern Energy GasEastern Energy Gas Holdings, LLC and its subsidiaries
RegistrantsBerkshire Hathaway Energy Company, PacifiCorp MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific
Subsidiary RegistrantsPacifiCorp, MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific
Northern PowergridNorthern Powergrid Holdings Company
Northern Natural GasNorthern Natural Gas Company
Kern RiverKern River Gas Transmission Company
AltaLinkBHE Canada Holdings Corporation
ALPAltaLink, L.P.
BHE U.S. TransmissionBHE U.S. Transmission, LLC
HomeServicesHomeServices of America, Inc. and its subsidiaries,
BHE Pipeline Group or Pipeline CompaniesConsists of Northern Natural Gas and Kern River
BHE TransmissionConsists of AltaLink and BHE U.S. Transmission
BHE RenewablesConsists of BHE Renewables, MidAmerican Funding, LLC and CalEnergy Philippines
UtilitiesPacifiCorp,its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries and Eastern Energy Gas Holdings, LLC and its subsidiaries
Berkshire HathawayNorthern PowergridBerkshire Hathaway Inc.Northern Powergrid Holdings Company
BHE Pipeline GroupBHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
Certain Industry TermsBHE GT&SBHE GT&S, LLC
AESONorthern Natural GasAlberta Electric System OperatorNorthern Natural Gas Company
AFUDCKern RiverAllowance for Funds Used During ConstructionKern River Gas Transmission Company
AUCBHE TransmissionAlberta Utilities CommissionBHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
CPUCBHE CanadaCalifornia Public Utilities CommissionBHE Canada Holdings Corporation
DthAltaLinkDecathermsAltaLink, L.P.
EPABHE U.S. TransmissionUnited States Environmental Protection AgencyBHE U.S. Transmission, LLC
FERCBHE RenewablesFederal Energy Regulatory CommissionBHE Renewables, LLC and CalEnergy Philippines
GHGHomeServicesGreenhouse GasesHomeServices of America, Inc. and its subsidiaries
GWhUtilitiesGigawatt HoursPacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
GTADomestic Regulated BusinessesGeneral Tariff ApplicationPacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
IPUCEGTSIdaho Public Utilities CommissionEastern Gas Transmission and Storage, Inc.
IUBGT&S TransactionIowa Utilities BoardThe acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy and Dominion Questar, exclusive of the Questar Pipeline Group on November 1, 2020
kVDEIKilovoltDominion Energy, Inc.
MWQuestar Pipeline GroupMegawattsDominion Energy Questar Pipeline, LLC and related entities

ii


MWhMegawatt Hours
OPUC
ii

Certain Industry Terms
2017 Tax ReformThe Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AFUDCAllowance for Funds Used During Construction
AUCAlberta Utilities Commission
BARTBest Available Retrofit Technology
COVID-19Coronavirus Disease 2019
CPSTCustomer Price Stability Tariff
CPUCCalifornia Public Utilities Commission
CSAPRCross-State Air Pollution Rule
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DthDecatherm
ECAMEnergy Cost Adjustment Mechanism
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
FIPFederal Implementation Plan
GAAPAccounting principles generally accepted in the United States of America
GEMAGas and Electricity Markets Authority
GHGGreenhouse Gases
GTAGeneral Tariff Application
GWhGigawatt Hour
IPUCIdaho Public Utilities Commission
IRPIntegrated Resource Plan
IUBIowa Utilities Board
kVKilovolt
MWMegawatt
MWhMegawatt Hour
NAAQSNational Ambient Air Quality Standards
NOx
Nitrogen Oxides
OfgemOffice of Gas and Electric Markets
OPUCOregon Public Utility Commission
PUCNPTCProduction Tax Credit
PUCNPublic Utilities Commission of Nevada
RECRACRenewable Adjustment Clause
RECRenewable Energy Credit
RPSRFPRequest for Proposal
RPSRenewable Portfolio Standards
SEC
SCRSelective Catalytic Reduction
SECUnited States Securities and Exchange Commission
SIPState Implementation Plan
UPSC
SO2
Sulfur Dioxide
UPSCUtah Public Service Commission
WPSCWyoming Public Service Commission
WUTCWashington Utilities and Transportation Commission

iii

Forward-Looking Statements


This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
•general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries;
•changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;
•the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;
•changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;
•performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;
•the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining accidents,incidents, litigation, wars, terrorism, pandemics (including potentially in relation to COVID-19), embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;
•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses arising from catastrophic events, such as wildfires where the Registrants may be found liable for property damages regardless of fault;
•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;
•the financial condition, creditworthiness and creditworthinessoperational stability of the respective Registrant's significant customers and suppliers;
•changes in business strategy or development plans;
•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;
•changes in the respective Registrant's credit ratings;
•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;

iii


•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
iv

•increases in employee healthcare costs;
•the impact of investment performance, certain participant elections such as lump sum distributions and changes in interest rates, legislation, healthcare cost trends, mortality, and morbidity on pension and other postretirement benefits expense and funding requirements;
•changes in the residential real estate brokerage, mortgage and mortgagefranchising industries and regulations that could affect brokerage, mortgage and mortgagefranchising transactions;
•the ability to successfully integrate the portion of the natural gas transmission and storage business acquired from DEI on November 1, 2020, and future acquired operations into a Registrant's business;
•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the consolidated financial results of the respective Registrants; and
the ability to successfully integrate future acquired operations into a Registrant's business; and
•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.



iv
v



Item 1.Financial Statements
Item 1.Financial Statements
Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm
4
Consolidated Balance Sheets
5
Consolidated Statements of Operations
7
Consolidated Statements of Comprehensive Income
8
Consolidated Statements of Changes in Equity
9
Consolidated Statements of Cash Flows
10
Notes to Consolidated Financial Statements
11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm
5458
Consolidated Balance Sheets
5559
Consolidated Statements of Operations
5761
Consolidated Statements of Changes in Shareholders' Equity
5862
Consolidated Statements of Cash Flows
5963
Notes to Consolidated Financial Statements
6064
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm
7684
Balance Sheets
7785
Statements of Operations
7987
Statements of Changes in Shareholder's Equity
8088
Statements of Cash Flows
8189
Notes to Financial Statements
8290
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm
9199
Consolidated Balance Sheets
92100
Consolidated Statements of Operations
94102
Consolidated Statements of Changes in Member's Equity
95103
Consolidated Statements of Cash Flows
96104
Notes to Consolidated Financial Statements
97105
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm
111121
Consolidated Balance Sheets
112122
Consolidated Statements of Operations
113123
Consolidated Statements of Changes in Shareholder's Equity
114124
Consolidated Statements of Cash Flows
115125
Notes to Consolidated Financial Statements
116126
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm
132141
Consolidated Balance Sheets
133142
Consolidated Statements of Operations
134143
Consolidated Statements of Changes in Shareholder's Equity
135144
Consolidated Statements of Cash Flows
136145
Notes to Consolidated Financial Statements
137146




Eastern Energy Gas Holdings, LLC and its subsidiaries
Item 2.
Report of Independent Registered Public Accounting Firm
Management's Discussion and Analysis of Financial Condition and Results
161
Consolidated Balance Sheets
162
Consolidated Statements of Operations
164
Consolidated Statements of Comprehensive Income
165
Consolidated Statements of Changes in Equity
166
Consolidated Statements of Cash Flows
167
Notes to Consolidated Financial Statements
168


1

Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
3031
6874
100109
125132
145153
181





2

Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section



3




PART I
Item 1.Financial Statements

Item 1.Financial Statements



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company
Des Moines, Iowa

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2017, and2021, the related consolidated statements of operations, and comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, and of changes in equity and cash flows for the nine-month periods ended September 30, 20172021 and 2016. These2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements areinformation for it to be in conformity with accounting principles generally accepted in the responsibilityUnited States of the Company's management.America.


We conducted our reviewshave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of the Company as of December 31, 2020, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States),PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.



/s/ Deloitte & Touche LLP




Des Moines, Iowa
November 3, 2017

5, 2021

4

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)


 As of
 September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$2,709 $1,290 
Restricted cash and cash equivalents216 140 
Trade receivables, net2,545 2,107 
Inventories1,129 1,168 
Mortgage loans held for sale1,687 2,001 
Other current assets2,142 2,741 
Total current assets10,428 9,447 
   
Property, plant and equipment, net88,062 86,128 
Goodwill11,572 11,506 
Regulatory assets3,372 3,157 
Investments and restricted cash and cash equivalents and investments15,218 14,320 
Other assets2,902 2,758 
  
Total assets$131,554 $127,316 
 As of
 September 30, December 31,
 2017 2016
ASSETS
Current assets:   
Cash and cash equivalents$1,142
 $721
Trade receivables, net1,994
 1,751
Inventories887
 925
Mortgage loans held for sale534
 359
Other current assets1,095
 917
Total current assets5,652
 4,673
  
  
Property, plant and equipment, net64,979
 62,509
Goodwill9,700
 9,010
Regulatory assets4,582
 4,307
Investments and restricted cash and investments4,987
 3,945
Other assets1,154
 996
  
  
Total assets$91,054
 $85,440


The accompanying notes are an integral part of these consolidated financial statements.



5


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)


 As of
 September 30,December 31,
20212020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$1,798 $1,867 
Accrued interest622 555 
Accrued property, income and other taxes670 582 
Accrued employee expenses556 383 
Short-term debt1,968 2,286 
Current portion of long-term debt1,179 1,839 
Other current liabilities2,054 1,626 
Total current liabilities8,847 9,138 
  
BHE senior debt13,001 12,997 
BHE junior subordinated debentures100 100 
Subsidiary debt35,818 34,930 
Regulatory liabilities6,958 7,221 
Deferred income taxes12,910 11,775 
Other long-term liabilities4,304 4,178 
Total liabilities81,938 80,339 
   
Commitments and contingencies (Note 9)00
   
Equity:  
BHE shareholders' equity:  
Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding2,300 3,750 
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding— — 
Additional paid-in capital6,374 6,377 
Long-term income tax receivable(658)(658)
Retained earnings39,199 35,093 
Accumulated other comprehensive loss, net(1,523)(1,552)
Total BHE shareholders' equity45,692 43,010 
Noncontrolling interests3,924 3,967 
Total equity49,616 46,977 
  
Total liabilities and equity$131,554 $127,316 
 As of
 September 30, December 31,
 2017 2016
LIABILITIES AND EQUITY
Current liabilities:   
Accounts payable$1,303
 $1,317
Accrued interest523
 454
Accrued property, income and other taxes780
 389
Accrued employee expenses392
 261
Short-term debt2,493
 1,869
Current portion of long-term debt3,070
 1,006
Other current liabilities1,034
 1,017
Total current liabilities9,595
 6,313
  
  
Regulatory liabilities3,086
 2,933
BHE senior debt6,771
 7,418
BHE junior subordinated debentures100
 944
Subsidiary debt26,183
 26,748
Deferred income taxes14,832
 13,879
Other long-term liabilities2,883
 2,742
Total liabilities63,450
 60,977
  
  
Commitments and contingencies (Note 11)

 

  
  
Equity: 
  
BHE shareholders' equity: 
  
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding—
 —
Additional paid-in capital6,362
 6,390
Retained earnings21,534
 19,448
Accumulated other comprehensive loss, net(423) (1,511)
Total BHE shareholders' equity27,473
 24,327
Noncontrolling interests131
 136
Total equity27,604
 24,463
  
  
Total liabilities and equity$91,054
 $85,440


The accompanying notes are an integral part of these consolidated financial statements.




6

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)


 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating revenue:
Energy$5,225 $4,451 $14,375 $11,504 
Real estate1,743 1,742 4,738 3,828 
Total operating revenue6,968 6,193 19,113 15,332 
    
Operating expenses:   
Energy:   
Cost of sales1,385 1,169 4,064 3,095 
Operations and maintenance1,001 1,033 2,972 2,564 
Depreciation and amortization946 789 2,797 2,323 
Property and other taxes194 152 593 456 
Real estate1,608 1,503 4,312 3,492 
Total operating expenses5,134 4,646 14,738 11,930 
     
Operating income1,834 1,547 4,375 3,402 
    
Other income (expense):   
Interest expense(531)(504)(1,593)(1,490)
Capitalized interest18 24 46 60 
Allowance for equity funds34 50 90 122 
Interest and dividend income18 17 65 57 
Gains on marketable securities, net294 1,797 1,142 2,407 
Other, net8 36 64 61 
Total other income (expense)(159)1,420 (186)1,217 
    
Income before income tax (benefit) expense and equity loss1,675 2,967 4,189 4,619 
Income tax (benefit) expense(355)80 (563)(111)
Equity loss(5)(41)(234)(91)
Net income2,025 2,846 4,518 4,639 
Net income attributable to noncontrolling interests103 4 311 11 
Net income attributable to BHE shareholders1,922 2,842 4,207 4,628 
Preferred dividends26 — 101 — 
Earnings on common shares$1,896 $2,842 $4,106 $4,628 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Operating revenue:       
Energy$4,322
 $4,272
 $11,501
 $11,102
Real estate961
 820
 2,502
 2,152
Total operating revenue5,283
 5,092
 14,003
 13,254
        
Operating costs and expenses:       
Energy:       
Cost of sales1,212
 1,187
 3,380
 3,252
Operating expense930
 948
 2,763
 2,739
Depreciation and amortization635
 639
 1,905
 1,898
Real estate882
 733
 2,311
 1,973
Total operating costs and expenses3,659
 3,507
 10,359
 9,862
        
Operating income1,624
 1,585
 3,644
 3,392
        
Other income (expense):       
Interest expense(464) (460) (1,379) (1,401)
Capitalized interest14
 14
 34
 128
Allowance for equity funds24
 17
 59
 147
Interest and dividend income32
 39
 85
 93
Other, net2
 15
 24
 26
Total other income (expense)(392) (375) (1,177) (1,007)
        
Income before income tax expense and equity income1,232
 1,210
 2,467
 2,385
Income tax expense184
 199
 319
 394
Equity income30
 36
 80
 96
Net income1,078
 1,047
 2,228
 2,087
Net income attributable to noncontrolling interests10
 11
 30
 25
Net income attributable to BHE shareholders$1,068
 $1,036
 $2,198
 $2,062


The accompanying notes are an integral part of these consolidated financial statements.
 

7


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)


 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
 
Net income$2,025 $2,846 $4,518 $4,639 
 
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $7, $(3), $12 and $1022 (6)44 38 
Foreign currency translation adjustment(218)244 (59)(195)
Unrealized gains (losses) on cash flow hedges, net of tax of $12, $2, $16 and $(5)33 4 48 (20)
Total other comprehensive (loss) income, net of tax(163)242 33 (177)
     
Comprehensive income1,862 3,088 4,551 4,462 
Comprehensive income attributable to noncontrolling interests103 4 315 11 
Comprehensive income attributable to BHE shareholders$1,759 $3,084 $4,236 $4,451 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Net income$1,078
 $1,047
 $2,228
 $2,087
        
Other comprehensive income, net of tax:       
Unrecognized amounts on retirement benefits, net of tax of $1, $7, $(3), and $2615
 18
 16
 80
Foreign currency translation adjustment227
 (134) 535
 (339)
Unrealized gains on available-for-sale securities, net of tax of $284, $53, $355 and $89423
 80
 542
 151
Unrealized gains (losses) on cash flow hedges, net of tax of $1, $(3), $(3) and $(1)1
 (3) (5) (2)
Total other comprehensive income, net of tax666
 (39) 1,088
 (110)
  
  
  
  
Comprehensive income1,744
 1,008
 3,316
 1,977
Comprehensive income attributable to noncontrolling interests10
 11
 30
 25
Comprehensive income attributable to BHE shareholders$1,734
 $997
 $3,286
 $1,952


The accompanying notes are an integral part of these consolidated financial statements.




8

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)

 BHE Shareholders' Equity
Long-termAccumulated
AdditionalIncomeOther
PreferredCommonPaid-inTaxRetainedComprehensiveNoncontrollingTotal
 StockStockCapitalReceivableEarningsLoss, NetInterestsEquity
Balance, June 30, 2020$— $— $6,377 $(530)$29,962 $(2,125)$101 $33,785 
Net income— — — — 2,842 — 3 2,845 
Other comprehensive income— — — — — 242 — 242 
Distributions— — — — — — (4)(4)
Other equity transactions— — — — — — 1 1 
Balance, September 30, 2020$— $— $6,377 $(530)$32,804 $(1,883)$101 $36,869 
        
Balance, December 31, 2019$— $— $6,389 $(530)$28,296 $(1,706)$129 $32,578 
Net income— — — — 4,628 — 10 4,638 
Other comprehensive loss— — — — — (177)— (177)
Common stock purchases— — (6)— (120)— — (126)
Distributions— — — — — — (11)(11)
Purchase of noncontrolling interest— — (5)— — — (28)(33)
Other equity transactions— — (1)— — — 1 — 
Balance, September 30, 2020$— $— $6,377 $(530)$32,804 $(1,883)$101 $36,869 
Balance, June 30, 2021$3,750 $— $6,377 $(658)$37,303 $(1,360)$3,953 $49,365 
Net income— — — — 1,922 — 103 2,025 
Other comprehensive loss— — — — — (163)— (163)
Preferred stock redemptions(1,450)— — — — — — (1,450)
Preferred stock dividend— — — — (26)— — (26)
Distributions— — — — — — (130)(130)
Purchase of noncontrolling interest— — (3)— — — — (3)
Other equity transactions— — — — — — (2)(2)
Balance, September 30, 2021$2,300 $— $6,374 $(658)$39,199 $(1,523)$3,924 $49,616 
        
Balance, December 31, 2020$3,750 $— $6,377 $(658)$35,093 $(1,552)$3,967 $46,977 
Net income— — — — 4,207 — 311 4,518 
Other comprehensive income— — — — — 29 4 33 
Preferred stock redemptions(1,450)— — — — — — (1,450)
Preferred stock dividend— — — — (101)— — (101)
Distributions— — — — — — (364)(364)
Contributions— — — — — — 9 9 
Purchase of noncontrolling interest— — (3)— — — — (3)
Other equity transactions— — — — — — (3)(3)
Balance, September 30, 2021$2,300 $— $6,374 $(658)$39,199 $(1,523)$3,924 $49,616 
 BHE Shareholders' Equity    
         Accumulated    
     Additional   Other    
 Common Paid-in Retained Comprehensive Noncontrolling Total
 Shares Stock Capital Earnings Loss, Net Interests Equity
              
Balance, December 31, 201577
 $—
 $6,403
 $16,906
 $(908) $134
 $22,535
Net income—
 —
 —
 2,062
 —
 14
 2,076
Other comprehensive loss—
 —
 —
 —
 (110) —
 (110)
Distributions—
 —
 —
 —
 —
 (14) (14)
Other equity transactions—
 —
 1
 —
 —
 8
 9
Balance, September 30, 201677
 $—
 $6,404
 $18,968
 $(1,018) $142
 $24,496
  
  
  
  
  
  
  
Balance, December 31, 201677
 $—
 $6,390
 $19,448
 $(1,511) $136
 $24,463
Net income—
 —
 —
 2,198
 —
 14
 2,212
Other comprehensive income—
 —
 —
 —
 1,088
 —
 1,088
Distributions—
 —
 —
 —
 —
 (16) (16)
Common stock purchases—
 —
 (1) (18) —
 —
 (19)
Common stock exchange—
 —
 (6) (94) —
 —
 (100)
Other equity transactions—
 —
 (21) —
 —
 (3) (24)
Balance, September 30, 201777
 $—
 $6,362
 $21,534
 $(423) $131
 $27,604


The accompanying notes are an integral part of these consolidated financial statements.

9



BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
 Nine-Month Periods
Ended September 30,
 20212020
Cash flows from operating activities:
Net income$4,518 $4,639 
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net(1,142)(2,407)
Depreciation and amortization2,834 2,357 
Allowance for equity funds(90)(122)
Equity loss, net of distributions346 146 
Changes in regulatory assets and liabilities(518)(87)
Deferred income taxes and investment tax credits, net661 791 
Other, net(88)(6)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets(13)(1,668)
Derivative collateral, net115 53 
Pension and other postretirement benefit plans(37)(69)
Accrued property, income and other taxes, net(29)97 
Accounts payable and other liabilities427 796 
Net cash flows from operating activities6,984 4,520 
Cash flows from investing activities:  
Capital expenditures(4,594)(4,607)
Acquisitions, net of cash acquired(64)— 
Purchases of marketable securities(243)(322)
Proceeds from sales of marketable securities222 308 
Proceeds from other investments1,296 13 
Equity method investments(54)(2,062)
Other, net(91)37 
Net cash flows from investing activities(3,528)(6,633)
Cash flows from financing activities:  
Preferred stock redemptions(1,450)— 
Preferred dividends(86)— 
Common stock purchases— (126)
Proceeds from BHE senior debt— 3,231 
Repayments of BHE senior debt(450)(350)
Proceeds from subsidiary debt2,014 2,648 
Repayments of subsidiary debt(1,271)(1,558)
Net repayments of short-term debt(316)(815)
Purchase of noncontrolling interest— (33)
Distributions to noncontrolling interests(366)(13)
Contributions from noncontrolling interests9 5 
Other, net(44)(52)
Net cash flows from financing activities(1,960)2,937 
Effect of exchange rate changes1 4 
Net change in cash and cash equivalents and restricted cash and cash equivalents1,497 828 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period1,445 1,268 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$2,942 $2,096 

 Nine-Month Periods
 Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income$2,228
 $2,087
Adjustments to reconcile net income to net cash flows from operating activities: 
  
Depreciation and amortization1,943
 1,922
Allowance for equity funds(59) (147)
Equity income, net of distributions(14) (62)
Changes in regulatory assets and liabilities17
 41
Deferred income taxes and amortization of investment tax credits573
 546
Other, net13
 (60)
Changes in other operating assets and liabilities, net of effects from acquisitions:   
Trade receivables and other assets(98) (348)
Derivative collateral, net(16) 22
Pension and other postretirement benefit plans(29) (73)
Accrued property, income and other taxes390
 713
Accounts payable and other liabilities170
 183
Net cash flows from operating activities5,118
 4,824
  
  
Cash flows from investing activities: 
  
Capital expenditures(3,179) (3,521)
Acquisitions, net of cash acquired(1,102) (66)
Increase in restricted cash and investments(45) (48)
Purchases of available-for-sale securities(167) (98)
Proceeds from sales of available-for-sale securities186
 125
Equity method investments(54) (462)
Other, net(12) (47)
Net cash flows from investing activities(4,373) (4,117)
  
  
Cash flows from financing activities: 
  
Repayments of BHE senior debt and junior subordinated debentures(1,344) (1,500)
Common stock purchases(19) —
Proceeds from subsidiary debt1,562
 1,484
Repayments of subsidiary debt(834) (1,613)
Net proceeds from short-term debt365
 887
Other, net(60) (50)
Net cash flows from financing activities(330) (792)
  
  
Effect of exchange rate changes6
 (5)
  
  
Net change in cash and cash equivalents421
 (90)
Cash and cash equivalents at beginning of period721
 1,108
Cash and cash equivalents at end of period$1,142
 $1,018


The accompanying notes are an integral part of these consolidated financial statements.

10


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(1)
General

(1)    General

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally-managedlocally 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 isCompany's operations are organized as eight8 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) Limitedplc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC ("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 ("AltaLink"BHE Canada") (which primarily consists of AltaLink, L.P. ("ALP"AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. (collectively withand its subsidiaries "HomeServices"("HomeServices"). The Company, through these locally managed and operated businesses, owns four4 utility companies in the United States serving customers in 11 states, two2 electricity distribution companies in Great Britain, two5 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 selling power generated frominvesting in wind, solar, wind, geothermal and hydroelectric sources under long-term contracts,projects, the second largest residential real estate brokerage firm in the United States and one1 of the largest residential real estate brokerage franchise networks in the United States.


The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 20172021 and for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The results of operations for the three- and nine-month periods ended September 30, 20172021 are not necessarily indicative of the results to be expected for the full year.


The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 20162020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period endedSeptember 30, 2017.2021.


(2)    New Accounting Pronouncements
11


(2)    Business Acquisition
In August 2017,
BHE GT&S Acquisition

Transaction Description

On November 1, 2020, BHE completed its acquisition of substantially all of the Financial Accounting Standards Boardnatural gas transmission and storage business of Dominion Energy, Inc. ("FASB"DEI") issued Accounting Standards Updateand Dominion Energy Questar Corporation ("ASU"Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") No. 2017-12,(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") (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy 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") (formerly known as Dominion Energy Cove Point LNG, LP), 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 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.

The assets acquired in the GT&S Transaction include (i) approximately 5,400 miles of operated natural gas transmission, gathering and storage pipelines with approximately 12.5 billion cubic feet ("Bcf") per day of design capacity; (ii) 420 Bcf of operated natural gas storage design capacity, of which amends FASB Accounting Standards Codification ("ASC") Topic 815, "Derivatives306 Bcf is owned by BHE GT&S; and Hedging." The amendments in this guidance update(iii) an LNG export, import and storage facility with LNG storage capacity of approximately 14.6 billions of cubic feet equivalent.

On October 5, 2020, DEI and Dominion Questar, as permitted under the hedge accounting modelterms of the GT&S Purchase Agreement, delivered notice to enable entities to better portray the economicsBHE of their risk management activitieselection to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the financial statements, expands an entity’s abilityexecution of the Q-Pipe Purchase Agreement referenced below, to hedge non-financialwaive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and financial risk componentsSale 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 reduces complexity in fair value hedges of interest rate risk. In addition, it eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item and also eases certain documentation and assessment requirements. 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 by means of a cumulative-effect adjustment to retained earningsindebtedness as of the beginningclosing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI is 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 fiscal yearQ-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 adoption. The Company is currently evaluatingapproximately $1.3 billion in cash.

Included in BHE's Consolidated Statement of Operations within the impact of adopting this guidance on its 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectivelyBHE Pipeline Group reportable segment for the presentation of the service cost componentthree- and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. The Company plans to adopt this guidance effective January 1, 2018. The Company does not believe this will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will 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. 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. The Company plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. The material impacts currently identified include recording the unrealized gains and losses on available-for-sale securities in the Consolidated Statements of Operations as opposed to other comprehensive income ("OCI"). For the nine-month periods ended September 30, 2017 and 2016, these amounts, net2021, is operating revenue of tax, were 542$516 million and 151$1,563 million, respectively.respectively and net income attributable to BHE shareholders of $74 million and $247 million, respectively, as a result of including BHE GT&S from November 1, 2020.

12


Allocation of Purchase Price


In May 2014,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 FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principlerate-setting authority of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or servicesFederal Energy Regulatory Commission ("FERC") and are accounted for pursuant to customers in an amount that reflectsGAAP, including the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementationauthoritative guidance for ASU No. 2014-09 but doregulated 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 changesubject to the core principle ofrate-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 guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. The Company currently does not expect theprojected timing and amount of revenue currently recognized to be materially different after adoptionfuture 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 new guidanceassets acquired and liabilities assumed as a majority of revenue is recognized when the Company has the right to invoice as it corresponds directly with the value to the customer of the Company’s performance to date. The Company's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by regulated energy, nonregulated energy and real estate, with further disaggregation of regulated energy by jurisdiction and real estate by line of business.acquisition date (in millions):

(3)
Business Acquisitions
Fair Value
Current assets, including cash and cash equivalents of $104$582 
Property, plant and equipment9,264 
Goodwill1,741 
Regulatory assets108 
Deferred income taxes284 
Other long-term assets1,424 
Total assets13,403 
Current liabilities, including current portion of long-term debt of $1,2001,616 
Long-term debt, less current portion4,415 
Regulatory liabilities650 
Other long-term liabilities292 
Total liabilities6,973 
Noncontrolling interest3,916 
Net assets acquired$2,514 

The Company completed various acquisitions totaling $1.1 billion, net of cash acquired, for
During the nine-month period ended September 30, 2017. 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 for each acquisition was allocated topaid over the estimated fair values of the identifiable assets acquired and liabilities assumed whichtotaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily related to residential real estate brokerage businesses, development and construction costs for the 110-megawatt Alamo 6 solar projectlong-term opportunity to improve operating results through the efficient management of operating expenses and the 50-megawatt Pearl solar project,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.
13

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of BHE and the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power. As a resultamortization of the various acquisitions,purchase price adjustments assuming the Company acquired assets of $1.1 billion, assumed liabilities of $476 million and recognized goodwill of $522 million.acquisition had taken place on January 1, 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):

Nine-Month Period
Ended September 30, 2020
(4)Operating revenue
Property, Plant and Equipment, $
16,791 
Net income attributable to BHE shareholders$4,468 


(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
   As of
 Depreciable September 30, December 31,
Life20212020
Regulated assets:   
Utility generation, transmission and distribution systems5-80 years $89,026  $86,730 
Interstate natural gas pipeline assets3-80 years 17,044  16,667 
   106,070 103,397 
Accumulated depreciation and amortization  (32,444) (30,662)
Regulated assets, net  73,626 72,735 
      
Nonregulated assets:     
Independent power plants5-30 years 7,058  7,012 
Other assets3-40 years 5,951  5,659 
   13,009 12,671 
Accumulated depreciation and amortization  (2,916) (2,586)
Nonregulated assets, net  10,093 10,085 
      
Net operating assets  83,719 82,820 
Construction work-in-progress  4,343  3,308 
Property, plant and equipment, net  $88,062 $86,128 
   As of
 Depreciable September 30, December 31,
 Life 2017 2016
Regulated assets:     
Utility generation, transmission and distribution systems5-80 years $73,138
 $71,536
Interstate natural gas pipeline assets3-80 years 6,991
 6,942
   80,129
 78,478
Accumulated depreciation and amortization  (24,525) (23,603)
Regulated assets, net  55,604
 54,875
    
  
Nonregulated assets:   
  
Independent power plants5-30 years 5,911
 5,594
Other assets3-30 years 1,265
 1,002
   7,176
 6,596
Accumulated depreciation and amortization  (1,304) (1,060)
Nonregulated assets, net  5,872
 5,536
    
  
Net operating assets  61,476
 60,411
Construction work-in-progress  3,503
 2,098
Property, plant and equipment, net  $64,979
 $62,509




Construction work-in-progress includes $3.1$3.9 billion as of September 30, 20172021 and $1.8$3.2 billion as of December 31, 2016,2020, related to the construction of regulated assets.


During the fourth quarter of 2016, MidAmerican Energy revised its electric
14

(4)    Investments and 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 depreciationRestricted Cash and amortization expense by $34 million annually, or $9 millionCash Equivalents and $26 million for the three- and nine-month periods ended September 30, 2017, based on depreciable plant balances at the time of the change.Investments

(5)
Investments and Restricted Cash and Investments


Investments and restricted cash and cash equivalents and investments consists of the following (in millions):
 As of
 September 30,December 31,
20212020
Investments:
BYD Company Limited common stock$7,023 $5,897 
Rabbi trusts473 440 
Other295 263 
Total investments7,791 6,600 
   
Equity method investments:
BHE Renewables tax equity investments5,253 5,626 
Iroquois Gas Transmission System, L.P.583 580 
Electric Transmission Texas, LLC578 594 
JAX LNG, LLC87 75 
Bridger Coal Company60 74 
Other163 118 
Total equity method investments6,724 7,067 
Restricted cash and cash equivalents and investments:  
Quad Cities Station nuclear decommissioning trust funds727 676 
Other restricted cash and cash equivalents233 155 
Total restricted cash and cash equivalents and investments960 831 
   
Total investments and restricted cash and cash equivalents and investments$15,475 $14,498 
Reflected as:
Current assets$257 $178 
Noncurrent assets15,218 14,320 
Total investments and restricted cash and cash equivalents and investments$15,475 $14,498 
 As of
 September 30, December 31,
 2017 2016
Investments:   
BYD Company Limited common stock$2,087
 $1,185
Rabbi trusts431
 403
Other132
 106
Total investments2,650
 1,694
  
  
Equity method investments:   
BHE Renewables tax equity investments804
 741
Electric Transmission Texas, LLC693
 672
Bridger Coal Company140
 165
Other158
 142
Total equity method investments1,795
 1,720
    
Restricted cash and investments: 
  
Quad Cities Station nuclear decommissioning trust funds498
 460
Other317
 282
Total restricted cash and investments815
 742
  
  
Total investments and restricted cash and investments$5,260
 $4,156
    
Reflected as:   
Other current assets$273
 $211
Noncurrent assets4,987
 3,945
Total investments and restricted cash and investments$5,260
 $4,156


Investments


BHE's investmentGains on marketable securities, net recognized during the period consists of the following (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Unrealized gains recognized on marketable securities still held at the reporting date$294 $1,794 $1,141 $2,403 
Net gains recognized on marketable securities sold during the period— 3 1 4 
Gains on marketable securities, net$294 $1,797 $1,142 $2,407 


15

Equity Method Investments

The Company has invested in BYDprojects sponsored by third parties, commonly referred to as tax equity investments. Once a project achieves commercial operation, the Company Limited common stock is accountedenters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project. Certain of the Company's tax equity investments are located in Texas and have physical settlement hedge obligations that were negatively impacted due to production shortfalls during periods of extreme market pricing volatility as a result of the February 2021 polar vortex weather event. The Company recognized pre-tax equity losses of $353 million, or after-tax income of $123 million inclusive of production tax credits ("PTCs") of $401 million and other income tax benefits of $79 million, during the nine-month period ended September 30, 2021, on its tax equity investments, largely due to the February 2021 polar vortex weather event. The losses for the impacted tax equity investments were based upon the terms of each partnership agreement, as an available-for-sale security with changes in fair value recognized in accumulated other comprehensive income (loss) ("AOCI"). The fairamended, and are subject to change as project-by-project discussions are ongoing among the Company and the respective hedge provider and project sponsor. As of September 30, 2021, the carrying value of BHE's investmentthe impacted tax equity investments totaled $2.8 billion.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in BYD Company Limited common stock reflectsmoney market mutual funds, United States Treasury Bills and other investments with a pre-tax unrealized gainmaturity of $1,855 millionthree months or less when purchased. Cash and $953 millioncash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 20172021 and December 31, 2016, respectively.2020, 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 of September 30, 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
September 30,December 31,
20212020
Cash and cash equivalents$2,709 $1,290 
Restricted cash and cash equivalents216 140 
Investments and restricted cash and cash equivalents and investments17 15 
Total cash and cash equivalents and restricted cash and cash equivalents$2,942 $1,445 


(6)
Recent Financing Transactions

(5)    Recent Financing Transactions

Long-Term Debt


In November 2021, PacifiCorp exercised its par call redemption option, available in the first ninefinal three months of 2017, BHE repaid at par value a total of $944prior to scheduled maturity, and redeemed $450 million plus accrued interest, of its junior subordinated debentures2.95% Series First Mortgage Bonds that was originally due December 2044.February 2022.


In September 2017,2021, HomeServices entered into a $250$150 million unsecured amortizing term loan due September 2026. The net proceeds were used to fund the repayment of its existing unsecured amortizing term loan due September 2022. The amortizing term loan has an underlying variable interest rate based on the London Interbank Offered Rate ("LIBOR") plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to acquisitions.

In July 2017, Northern Powergrid Metering Limited entered into a £200 million secured amortizing corporate facility with a stated maturity of June 2026. The amortizing facility has a variable interest rate based on the LIBOR plus a spread that varies based on an agreed-upon schedule. In July 2017, Northern Powergrid Metering Limited received proceeds of £120 million under the facility to repay amounts provided by Yorkshire Electricity Group plc which provides internal funds for the continuing smart meter deployment program of Northern Powergrid Metering Limited. Northern Powergrid Metering Limited has entered into interest rate swaps that fix the underlying interest rate on 85% of the outstanding debt.

In July 2017, Cordova Funding Corporation redeemed the remaining $89 million of its 8.48% to 9.07% Series A Senior Secured Bonds due December 2019, CE Generation, LLC redeemed the remaining $51 million of its 7.416% Senior Secured Bonds due December 2018, and Salton Sea Funding Corporation redeemed the remaining $20 million of its 7.475% Senior Secured Series F Bonds due November 2018, each at redemption prices determined in accordance with the terms of the respective indentures.

In June 2017, BHE issued $100 million of its 5.0% junior subordinated debentures due June 2057 in exchange for 181,819 shares of BHE no par value common stock held by a minority shareholder. The junior subordinated debentures are redeemable at BHE's option at any time from and after June 15, 2037, at par plus accrued and unpaid interest.

In May 2017, Alamo 6, LLC issued $232 million of its 4.17% Senior Secured Notes due March 2042. The principal of the notes amortizes beginning March 2018 with a final maturity in March 2042. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to the development, construction and financing of a 110-megawatt solar project in Texas.

In April 2017, Kern River redeemed the remaining $175 million of its 4.893% Senior Notes due April 2018 at a redemption price determined in accordance with the terms of the indenture.

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% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds.

In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.

Credit Facilities

In September 2017, HomeServices terminated its $350 million unsecured credit facility expiring July 2018 and entered into a $600 million unsecured credit facility expiring September 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 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.


In June 2017, BHE extended,July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with lender consent,respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the maturity date to June 2020 forrepowering of certain of its $2.0 billion unsecured credit facility and PacifiCorp extended,existing wind-powered generating facilities, which were previously financed with lender consent, the maturity date to June 2020 for its $400 million unsecured credit facility, each by exercising the first of two available one-year extensions.MidAmerican Energy's general funds.




In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2017,2052. PacifiCorp terminatedused 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.
16

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.

In April 2021, Northern Natural Gas issued $550 million of 3.40% Senior Bonds due October 2051. Northern Natural Gas used the net proceeds to early redeem in April 2021 all of its $200 million, 4.25% Senior Notes originally due June 2021 and for general corporate purposes.

Credit Facilities

In September 2021, HomeServices amended and restated its existing $600 million unsecured credit facility expiring March 2018in September 2022. The amendment increased the lender commitment to $700 million and entered into aextended the expiration date to September 2026.

In June 2021, BHE amended and restated its existing $3.5 billion unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2020 with two one-year 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. The credit facility requires 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.

2022. In June 2017, MidAmerican Energy terminated2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring March 2018in 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 entered into aincreased the available maturity extension options to an unlimited number, subject to lender consent.

In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring in June 20202022. 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 consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility expiring in August 2021.

In June 2021, Nevada Power and Sierra Pacific each amended and restated its existing $400 million and $250 million secured credit facilities, respectively, expiring in June 2022 with twono remaining one-year extension options. The amendments 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. The credit facility requires 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.


In June 2017, Nevada Power amendedMay 2021, AltaLink, L.P. extended, with lender consent, the expiration date for its $400existing C$75 million and C$500 million secured credit facility, extending the maturity datefacilities to June 2020 with twoDecember 2025 by exercising an available one-year extension options subject to lender consent. The amended 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 Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long-term debt securities. The amended credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not to exceed 0.65 to 1.0 as of the last day of each quarter.option.

In June 2017, Sierra Pacific amended its $250 million secured credit facility, extending the maturity date to June 2020 with two one-year extension options subject to lender consent. The amended 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. The amended credit facility requires Sierra Pacific'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.


In May 2017, BHE entered into a $1.0 billion2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$300 million unsecured credit facility expiring May 2018. Theto December 2025 by exercising an available one-year extension option.

In April 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one-year revolving 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, hasto April 2022, by exercising 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. The credit facility requires 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.one-year extension option.


17
(7)
Income Taxes


(6)    Income Taxes

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:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
 
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(31)(20)(29)(23)
State income tax, net of federal income tax impacts(4)3 — 2 
Income tax effect of foreign income(1)1 2 — 
Effects of ratemaking(6)(2)(5)(2)
Equity income— — (1)— 
Noncontrolling interest(1)— (2)— 
Other, net1 — 1 — 
Effective income tax rate(21)%3 %(13)%(2)%
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Federal statutory income tax rate35 % 35 % 35 % 35 %
Income tax credits(19) (16) (18) (15)
State income tax, net of federal income tax benefit—
 —
 (1) —
Income tax effect of foreign income(3) (3) (4) (4)
Equity income1
 1
 1
 1
Other, net1
 (1) —

—
Effective income tax rate15 % 16 % 13 % 17 %




Income tax credits relate primarily to production tax creditsPTCs 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 nine-month periods ended September 30, 2021 and 2020 totaled $1.2 billion and $1.0 billion, respectively.


Berkshire HathawayIncome tax effect on foreign income includes, the Company in its United States federalamong other items, a deferred income tax return. charge of $109 million recognized in June 2021 upon the enactment of an increase in the United Kingdom's corporate income tax rate from 19% to 25% effective April 1, 2023, and a deferred income tax charge of $35 million recognized in July 2020 related to the United Kingdom's corporate income tax rate that was scheduled to decrease from 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,basis. Berkshire Hathaway includes the Company in its consolidated United States federal and substantially allIowa state income tax returns and the majority of its currently payable or receivablethe Company's United States federal income taxes aretax is remitted to or received from Berkshire Hathaway. For the nine-month periods ended September 30, 20172021 and 2016,2020, the Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $659 million$1.3 billion and $860 million,$1.0 billion, respectively.


(8)
Employee Benefit Plans

18

(7)    Employee Benefit Plans

Domestic Operations


Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):

 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Pension:
Service cost$7 $4 $22 $11 
Interest cost21 23 59 69 
Expected return on plan assets(32)(35)(101)(105)
Settlement4 — 4 — 
Net amortization6 8 19 25 
Net periodic benefit cost$6 $— $3 $— 
Other postretirement:
Service cost$2 $1 $8 $5 
Interest cost4 6 14 16 
Expected return on plan assets(5)(9)(16)(25)
Net amortization— (1)(2)(5)
Net periodic benefit cost (credit)$1 $(3)$4 $(9)

 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Pension:       
Service cost$6
 $7
 $18
 $22
Interest cost29
 31
 87
 94
Expected return on plan assets(40) (39) (120) (120)
Net amortization7
 12
 22
 36
Net periodic benefit cost$2
 $11
 $7
 $32
        
Other postretirement:       
Service cost$3
 $2
 $7
 $7
Interest cost7
 7
 21
 23
Expected return on plan assets(9) (10) (30) (31)
Net amortization(3) (2) (10) (9)
Net periodic benefit credit$(2) $(3) $(12) $(10)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $15$13 million and $5$13 million, respectively, during 2017.2021. As of September 30, 2017,2021, $9 million and $5$10 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.




Foreign Operations


Net periodic benefit costcredit for the United Kingdom pension plan included the following components (in millions):

Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
 
Service cost$4 $4 $12 $12 
Interest cost8 10 23 30 
Expected return on plan assets(28)(26)(84)(76)
Net amortization14 11 42 32 
Net periodic benefit credit$(2)$(1)$(7)$(2)

 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Service cost$6
 $5
 $19
 $16
Interest cost15
 17
 44
 55
Expected return on plan assets(25) (27) (74) (85)
Settlement18
 —
 18
 —
Net amortization17
 11
 50
 34
Net periodic benefit cost$31
 $6
 $57
 $20

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £45£20 million during 2017.2021. As of September 30, 2017, £342021, £17 million,, or $43$24 million,, of contributions had been made to the United Kingdom pension plan.

(9)
Risk Management and Hedging Activities

The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific (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. Interest rate risk exists on variable-rate debt, future debt issuances and mortgage commitments. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain and Canada. The Company does not engage in a material amount of proprietary trading activities.

Each of the Company's business platforms has established a risk management process that is designed to identify, assess, manage, monitor and report each of the various types of risk involved in its business. To mitigate 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 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, 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. The Company does not hedge all of its commodity price, interest rate and foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 10 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 the Company'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):



19
 Other   Other Other  
 Current Other Current Long-term  
 Assets Assets Liabilities Liabilities Total
As of September 30, 2017         
Not designated as hedging contracts:         
Commodity assets(1)
$16
 $93
 $7
 $3
 $119
Commodity liabilities(1)
(1) —
 (60) (135) (196)
Interest rate assets22
 —
 —
 —
 22
Interest rate liabilities—
 —
 (3) (7) (10)
Total37
 93
 (56) (139) (65)
  
  
  
  
  
Designated as hedging contracts: 
  
  
  
  
Commodity assets—
 —
 2
 6
 8
Commodity liabilities—
 —
 (11) (17) (28)
Interest rate assets—
 6
 —
 —
 6
Interest rate liabilities—
 —
 (1) —
 (1)
Total—
 6
 (10) (11) (15)
  
  
  
  
  
Total derivatives37
 99
 (66) (150) (80)
Cash collateral receivable—
 —
 21
 64
 85
Total derivatives - net basis$37
 $99
 $(45) $(86) $5

 Other   Other Other  
 Current Other Current Long-term  
 Assets Assets Liabilities Liabilities Total
As of December 31, 2016         
Not designated as hedging contracts:         
Commodity assets(1)
$42
 $86
 $5
 $2
 $135
Commodity liabilities(1)
(10) —
 (46) (150) (206)
Interest rate assets15
 —
 —
 —
 15
Interest rate liabilities—
 —
 (4) (6) (10)
Total47
 86
 (45) (154) (66)
          
Designated as hedging contracts:         
Commodity assets1
 —
 2
 3
 6
Commodity liabilities—
 —
 (14) (8) (22)
Interest rate assets—
 8
 —
 —
 8
Interest rate liabilities—
 —
 (3) —
 (3)
Total1
 8
 (15) (5) (11)
          
Total derivatives48
 94
 (60) (159) (77)
Cash collateral receivable—
 —
 13
 61
 74
Total derivatives - net basis$48
 $94
 $(47) $(98) $(3)
(8)    Fair Value Measurements
(1)
The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2017 and December 31, 2016, a net regulatory asset of $162 million and $148 million, respectively, was recorded related to the net derivative liability of $77 million and $71 million, respectively. The difference between the net regulatory asset and the net derivative liability relates primarily to a power purchase agreement derivative at BHE Renewables.



Not Designated as Hedging Contracts

The following table reconciles the beginning and ending balances of the Company'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 (in millions):
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Beginning balance$162
 $185
 $148
 $250
Changes in fair value recognized in net regulatory assets10
 18
 43
 5
Net (losses) gains reclassified to operating revenue(5) (3) 9
 (6)
Net losses reclassified to cost of sales(5) (5) (38) (54)
Ending balance$162
 $195
 $162
 $195

Designated as Hedging Contracts

The Company uses commodity derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. Certain commodity derivative contracts have settled and the fair value at the date of settlement remains in AOCI and is recognized in earnings when the forecasted transactions impact earnings. The following table reconciles the beginning and ending balances of the Company's accumulated other comprehensive (income) loss (pre-tax) and summarizes pre-tax gains and losses on commodity derivative contracts designated and qualifying as cash flow hedges recognized in OCI, as well as amounts reclassified to earnings (in millions):
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Beginning balance$21
 $26
 $16
 $46
Changes in fair value recognized in OCI5
 15
 28
 35
Net gains reclassified to operating revenue—
 1
 —
 1
Net losses reclassified to cost of sales(7) (7) (25) (47)
Ending balance$19
 $35
 $19
 $35
Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three- and nine-month periods ended September 30, 2017 and 2016, hedge ineffectiveness was insignificant. As of September 30, 2017, the Company had cash flow hedges with expiration dates extending through June 2026 and $10 million of pre-tax unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.


Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
 Unit of September 30, December 31,
 Measure 2017 2016
      
Electricity purchasesMegawatt hours 9
 5
Natural gas purchasesDecatherms 339
 271
Fuel purchasesGallons 2
 11
Interest rate swapsUS$ 694
 714
Interest rate swaps£ 102
 —
Mortgage sale commitments, netUS$ (442) (309)

Credit Risk

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.

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," 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 September 30, 2017, the applicable credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $190 million and $190 million as of September 30, 2017 and December 31, 2016, respectively, for which the Company had posted collateral of $73 million and $69 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 September 30, 2017 and December 31, 2016, the Company would have been required to post $105 million and $110 million, respectively, 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.




(10)
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 1Level 2Level 3
Other(1)
Total
As of September 30, 2021
Assets:
Commodity derivatives$15 $436 $88 $(49)$490 
Foreign currency exchange rate derivatives— 8 — — 8 
Interest rate derivatives— 12 30 — 42 
Mortgage loans held for sale— 1,687 — — 1,687 
Money market mutual funds2,017 — — — 2,017 
Debt securities:
United States government obligations228 — — — 228 
International government obligations— 2 — — 2 
Corporate obligations— 86 — — 86 
Municipal obligations— 3 — — 3 
Agency, asset and mortgage-backed obligations— 1 — — 1 
Equity securities:
United States companies398 — — — 398 
International companies7,031 — — — 7,031 
Investment funds264 — — — 264 
 $9,953 $2,235 $118 $(49)$12,257 
Liabilities:     
Commodity derivatives$(2)$(134)$(56)$80 $(112)
Foreign currency exchange rate derivatives— (4)— — (4)
Interest rate derivatives(1)(11)(2)— (14)
$(3)$(149)$(58)$80 $(130)
20

Input Levels for Fair Value Measurements
 Input Levels for Fair Value Measurements    Level 1Level 2Level 3
Other(1)
Total
 Level 1 Level 2 Level 3 
Other(1)
 Total
As of September 30, 2017          
As of December 31, 2020As of December 31, 2020
Assets:          Assets:
Commodity derivatives $1
 $24
 $102
 $(19) $108
Commodity derivatives$1 $73 $135 $(21)$188 
Foreign currency exchange rate derivativesForeign currency exchange rate derivatives— 20 — — 20 
Interest rate derivatives —
 14
 14
 —
 28
Interest rate derivatives— — 62 — 62 
Mortgage loans held for sale —
 534
 —
 —
 534
Mortgage loans held for sale— 2,001 — — 2,001 
Money market mutual funds(2)
 855
 —
 —
 —
 855
873 — — — 873 
Debt securities:          Debt securities:
United States government obligations 168
 —
 —
 —
 168
United States government obligations200 — — — 200 
International government obligations —
 5
 —
 —
 5
International government obligations— 5 — — 5 
Corporate obligations —
 37
 —
 —
 37
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 270
 —
 —
 —
 270
United States companies381 — — — 381 
International companies 2,094
 —
 —
 —
 2,094
International companies5,906 — — — 5,906 
Investment funds 182
 —
 —
 —
 182
Investment funds201 — — — 201 
 $3,570

$617

$116

$(19) $4,284
 $7,562 $2,180 $197 $(21)$9,918 
Liabilities:  
  
  
  
  
Liabilities:
Commodity derivatives $(1)
$(207)
$(16)
$104
 $(120)Commodity derivatives$(1)$(90)$(19)$56 $(54)
Foreign currency exchange rate derivativesForeign currency exchange rate derivatives— (2)— — (2)
Interest rate derivatives —
 (10) (1) —
 (11)Interest rate derivatives(5)(60)— — (65)
 $(1) $(217) $(17) $104
 $(131)$(6)$(152)$(19)$56 $(121)



As of December 31, 2016          
Assets:          
Commodity derivatives $5
 $49
 $87
 $(22) $119
Interest rate derivatives —
 16
 7
 —
 23
Mortgage loans held for sale —
 359
 —
 —
 359
Money market mutual funds(2)
 586
 —
 —
 —
 586
Debt securities:          
United States government obligations 161
 —
 —
 —
 161
International government obligations —
 3
 —
 —
 3
Corporate obligations —
 36
 —
 —
 36
Municipal obligations —
 2
 —
 —
 2
Agency, asset and mortgage-backed obligations —
 2
 —
 —
 2
Equity securities:          
United States companies 250
 —
 —
 —
 250
International companies 1,190
 —
 —
 —
 1,190
Investment funds 147
 —
 —
 —
 147
  $2,339
 $467
 $94
 $(22) $2,878
Liabilities:          
Commodity derivatives $(2) $(199) $(27) $96
 $(132)
Interest rate derivatives (1) (11) (1) —
 (13)
  $(3) $(210) $(28) $96
 $(145)

(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $85 million and $74 million as of September 30, 2017 and December 31, 2016, 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.

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $31 million and $35 million as of September 30, 2021 and December 31, 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 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. Refer to Note 9 for further discussion regarding the Company's risk management and hedging activities.


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.



21

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value and are primarily accounted for as available-for-sale securities.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 assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
InterestInterest
 CommodityRateCommodityRate
DerivativesDerivativesDerivativesDerivatives
2021:
Beginning balance$105 $41 $116 $62 
Changes included in earnings(1)
(18)(13)(34)(34)
Changes in fair value recognized in OCI(6)— (13)— 
Changes in fair value recognized in net regulatory assets12 — 21 — 
Purchases1 — 2 — 
Settlements(62)— (60)— 
Ending balance$32 $28 $32 $28 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
   Interest Auction   Interest Auction
 Commodity Rate Rate Commodity Rate Rate
 Derivatives Derivatives Securities Derivatives Derivatives Securities
2017:           
Beginning balance$81
 $8
 $—
 $60
 $6
 $—
Changes included in earnings7
 34
 —
 19
 100
 —
Changes in fair value recognized in OCI(1) —
 —
 (3) —
 —
Changes in fair value recognized in net regulatory assets(3) —
 —
 (5) —
 —
Purchases—
 8
 —
 1
 6
 —
Settlements2
 (37) —
 14
 (99) —
Ending balance$86
 $13
 $—
 $86
 $13
 $—


Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
InterestInterest
CommodityRateCommodityRate
DerivativesDerivativesDerivativesDerivatives
2020:
Beginning balance$44 $78 $97 $14 
Changes included in earnings(1)
(7)10 (11)74 
Changes in fair value recognized in net regulatory assets20 — (36)— 
Purchases1 — 4 — 
Settlements38 — 42 — 
Ending balance$96 $88 $96 $88 

(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.


22
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
   Interest Auction   Interest Auction
 Commodity Rate Rate Commodity Rate Rate
 Derivatives Derivatives Securities Derivatives Derivatives Securities
2016:           
Beginning balance$44
 $14
 $18
 $47
 $4
 $44
Changes included in earnings9
 49
 —
 8
 103
 —
Changes in fair value recognized in OCI(2) —
 —
 (2) —
 6
Changes in fair value recognized in net regulatory assets(1) —
 —
 (12) —
 —
Purchases1
 —
 —
 1
 —
 —
Redemptions—
 —
 —
 —
 —
 (32)
Settlements5
 (52) —
 14
 (96) —
Ending balance$56
 $11
 $18
 $56
 $11
 $18


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 Balance Sheets. 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 (in millions):
 As of September 30, 2021As of December 31, 2020
 CarryingFairCarryingFair
ValueValueValueValue
 
Long-term debt$50,098 $57,902 $49,866 $60,633 

(9)    Commitments and Contingencies
 As of September 30, 2017 As of December 31, 2016
 Carrying Fair Carrying Fair
 Value Value Value Value
        
Long-term debt$36,124
 $41,197
 $36,116
 $40,718





(11)
Commitments and Contingencies

Fuel, Capacity and Transmission ContractConstruction Commitments


During the nine-month period ended September 30, 2017,2021, MidAmerican Energy amended certain of its natural gas supply and transportation contracts increasing minimum payments by $247entered into firm construction commitments totaling $405 million through the remainder of 2021 and $70 million for 2022 through 2037.related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.


Construction CommitmentsEasements


During the nine-month period ended September 30, 2017, MidAmerican Energy entered into contracts totaling $675 million for the construction of wind-powered generating facilities in 2017 through 2019, with remaining payments totaling $84 million for the fourth quarter of 2017, $340 million in 2018 and $8 million in 2019.

Operating Leases and Easements

During the nine-month period ended September 30, 2017,2021, MidAmerican Energy entered into non-cancelable easements with minimum paymentspayment commitments totaling $114$87 million through 20572061 for land in Iowa on which some of its wind-poweredwind- and solar-powered generating facilities will be located.


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. The Company 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 "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. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.


23

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.

As of September 30, 2021, 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, 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 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").

Congress failed, which is intended to pass legislation neededresolve disputes surrounding PacifiCorp's efforts to implementrelicense the original KHSA. On April 6, 2016,Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and CommerceCalifornia ("States") and other stakeholders executed an amendment to the KHSA. Consistentassess whether dam removal can occur consistent with the termssettlement's terms. For PacifiCorp, the key elements of the amended KHSA, on September 23, 2016, PacifiCorpsettlement 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 FERC license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC") jointly, 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 ana joint application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilitiesdams from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with theThe FERC to surrender the license and decommission the 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 KRRC is effective.

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 are protected from uncapped dam removal costscustomers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and liabilities.the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC must indemnifyto file a new license transfer application by January 16, 2021, to remove 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,the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of which up to $184 million would be collected from PacifiCorp's Oregon customerssurrender. On January 13, 2021, the new license transfer application was filed with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measureFERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in November 2014 from which the state of California's contribution towards facilities removal costs are being drawn.new license transfer application. In accordance with this bond measure,addition, the MOA provides for additional contingency funding of up$45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to $250 million for facilities removal costs was includedequally share in any additional cost overruns in the California state budget in 2016, with the funding effective for at least five years. If facilitiesunlikely event that dam removal costs exceed the combined$450 million in funding that will be availableto 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'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 and the States as co-licensees. The transfer will be effective after PacifiCorp will resume relicensing withsecures property transfer approvals from its state public utility commissions and 30 days following the FERC.issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah.


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.


24
(12)
Components of Other Comprehensive Income (Loss), Net



(10)    Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):
For the Three-Month Period Ended September 30, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,352 $736 $1,008 $— $— $— $— $— $3,096 
Retail gas— 84 16 — — — — — 100 
Wholesale58 113 19 — 14 — — (1)203 
Transmission and
   distribution		55 15 35 241 — 175 — — 521 
Interstate pipeline— — — — 514 — — (28)486 
Other26 — — — (2)— — — 24 
Total Regulated1,491 948 1,078 241 526 175 — (29)4,430 
Nonregulated— 2 — 8 257 12 288 141 708 
Total Customer Revenue1,491 950 1,078 249 783 187 288 112 5,138 
Other revenue— 16 7 28 2 (2)28 8 87 
Total$1,491 $966 $1,085 $277 $785 $185 $316 $120 $5,225 
For the Nine-Month Period Ended September 30, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$3,685 $1,704 $2,227 $— $— $— $— $(1)$7,615 
Retail gas— 633 74 — — — — — 707 
Wholesale124 307 44 — 31 — — (2)504 
Transmission and
   distribution		117 45 78 747 — 525 — — 1,512 
Interstate pipeline— — — — 1,787 — — (94)1,693 
Other80 — 1 — (1)— — — 80 
Total Regulated4,006 2,689 2,424 747 1,817 525 — (97)12,111 
Nonregulated— 13 1 26 726 27 693 452 1,938 
Total Customer Revenue4,006 2,702 2,425 773 2,543 552 693 355 14,049 
Other revenue25 24 18 84 41 (5)80 59 326 
Total$4,031 $2,726 $2,443 $857 $2,584 $547 $773 $414 $14,375 
25

For the Three-Month Period Ended September 30, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,344 $661 $977 $— $— $— $— $(1)$2,981 
Retail gas— 70 14 — — — — — 84 
Wholesale59 56 14 — — — — 1 130 
Transmission and
   distribution		33 15 30 208 — 169 — — 455 
Interstate pipeline— — — — 264 — — (29)235 
Other42 — — — — — — — 42 
Total Regulated1,478 802 1,035 208 264 169 — (29)3,927 
Nonregulated— 4 (1)6 — 6 270 145 430 
Total Customer Revenue1,478 806 1,034 214 264 175 270 116 4,357 
Other revenue1 6 8 32 — — 39 8 94 
Total$1,479 $812 $1,042 $246 $264 $175 $309 $124 $4,451 
For the Nine-Month Period Ended September 30, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$3,532 $1,539 $2,144 $— $— $— $— $(1)$7,214 
Retail gas— 341 81 — — — — — 422 
Wholesale76 157 34 — — — — (1)266 
Transmission and
   distribution		79 48 75 632 — 502 — — 1,336 
Interstate pipeline— — — — 885 — — (103)782 
Other88 — 1 — — — — — 89 
Total Regulated3,775 2,085 2,335 632 885 502 — (105)10,109 
Nonregulated— 13 1 18 — 14 641 394 1,081 
Total Customer Revenue3,775 2,098 2,336 650 885 516 641 289 11,190 
Other revenue54 16 23 83 5 — 90 43 314 
Total$3,829 $2,114 $2,359 $733 $890 $516 $731 $332 $11,504 

(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 (in millions):
HomeServices
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Customer Revenue:
Brokerage$1,563 $1,449 $4,154 $3,183 
Franchise23 23 65 54 
Total Customer Revenue1,586 1,472 4,219 3,237 
Mortgage and other revenue157 270 519 591 
Total$1,743 $1,742 $4,738 $3,828 
26

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 September 30, 2021, by reportable segment (in millions):
Performance obligations expected to be satisfied:
Less than 12 monthsMore than 12 monthsTotal
BHE Pipeline Group$2,586 $21,377 $23,963 
BHE Transmission175 — 175 
Total$2,761 $21,377 $24,138 

(11)    BHE Shareholders' Equity

On July 22, 2021, BHE redeemed at par 1,450,003 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $1.45 billion, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.

(12)    Components of Other Comprehensive Income (Loss), Net

The following table shows the change in AOCI attributable to BHE shareholdersaccumulated other comprehensive income (loss) by each component of OCI,other comprehensive income (loss), net of applicable income taxestax (in millions):
UnrecognizedForeignUnrealizedAOCI
Amounts onCurrency(Losses) GainsAttributable
RetirementTranslationon CashNoncontrollingTo BHE
BenefitsAdjustmentFlow HedgesInterestsShareholders, Net
Balance, December 31, 2019$(417)$(1,296)$7 $— $(1,706)
Other comprehensive income (loss)38 (195)(20)— (177)
Balance, September 30, 2020$(379)$(1,491)$(13)$— $(1,883)
Balance, December 31, 2020$(492)$(1,062)$(8)$10 $(1,552)
Other comprehensive income (loss)44 (59)48 (4)29 
Balance, September 30, 2021$(448)$(1,121)$40 $6 $(1,523)

27
      Unrealized   
  Unrecognized Foreign Gains on Unrealized AOCI
  Amounts on Currency Available- Gains (Losses) Attributable
  Retirement Translation For-Sale on Cash To BHE
  Benefits Adjustment Securities Flow Hedges Shareholders, Net
           
Balance, December 31, 2015 $(438) $(1,092) $615
 $7
 $(908)
Other comprehensive income (loss) 80
 (339) 151
 (2) (110)
Balance, September 30, 2016 $(358) $(1,431) $766
 $5
 $(1,018)
           
Balance, December 31, 2016 $(447) $(1,675) $585
 $26
 $(1,511)
Other comprehensive income (loss) 16
 535
 542
 (5) 1,088
Balance, September 30, 2017 $(431) $(1,140) $1,127
 $21
 $(423)


(13)    Segment Information
Reclassifications from AOCI to net income for the periods ended September 30, 2017 and 2016 were insignificant. For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 9. Additionally, refer to the "Foreign Operations" discussion in Note 8 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.




(13)
Segment Information


The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. 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):
 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating revenue:
PacifiCorp$1,491 $1,479 $4,031 $3,829 
MidAmerican Funding966 812 2,726 2,114 
NV Energy1,085 1,042 2,443 2,359 
Northern Powergrid277 246 857 733 
BHE Pipeline Group785 264 2,584 890 
BHE Transmission185 175 547 516 
BHE Renewables316 309 773 731 
HomeServices1,743 1,742 4,738 3,828 
BHE and Other(1)
120 124 414 332 
Total operating revenue$6,968 $6,193 $19,113 $15,332 
Depreciation and amortization:
PacifiCorp$272 $234 $811 $696 
MidAmerican Funding218 179 634 530 
NV Energy138 128 411 377 
Northern Powergrid73 69 217 195 
BHE Pipeline Group124 45 363 134 
BHE Transmission59 61 177 176 
BHE Renewables61 72 182 214 
HomeServices14 11 37 34 
BHE and Other(1)
1 1 2 1 
Total depreciation and amortization$960 $800 $2,834 $2,357 

28

Three-Month PeriodsNine-Month Periods
Three-Month Periods Nine-Month PeriodsEnded September 30,Ended September 30,
Ended September 30, Ended September 30, 2021202020212020
2017 2016 2017 2016
Operating revenue:       
Operating income:Operating income:  
PacifiCorp$1,430
 $1,434
 $3,956
 $3,919
PacifiCorp$394 $361 $911 $851 
MidAmerican Funding815
 797
 2,170
 2,008
MidAmerican Funding287 232 438 444 
NV Energy1,047
 987
 2,384
 2,309
NV Energy348 347 563 587 
Northern Powergrid221
 220
 685
 748
Northern Powergrid126 106 403 327 
BHE Pipeline Group193
 201
 700
 704
BHE Pipeline Group303 101 1,166 442 
BHE Transmission182
 169
 506
 309
BHE Transmission90 79 256 236 
BHE Renewables283
 273
 647
 582
BHE Renewables149 143 279 244 
HomeServices961
 820
 2,502
 2,152
HomeServices135 239 426 336 
BHE and Other(1)
151
 191
 453
 523
BHE and Other(1)
2 (61)(67)(65)
Total operating revenue$5,283
 $5,092
 $14,003
 $13,254
       
Depreciation and amortization:       
PacifiCorp$200
 $193
 $598
 $589
MidAmerican Funding112
 118
 370
 338
NV Energy105
 106
 315
 315
Northern Powergrid55
 49
 156
 149
BHE Pipeline Group42
 53
 115
 160
BHE Transmission58
 61
 165
 177
BHE Renewables63
 57
 187
 169
HomeServices16
 9
 38
 24
BHE and Other(1)
—
 2
 (1) 1
Total depreciation and amortization$651
 $648
 $1,943
 $1,922
Total operating incomeTotal operating income1,834 1,547 4,375 3,402 
Interest expenseInterest expense(531)(504)(1,593)(1,490)
Capitalized interestCapitalized interest18 24 46 60 
Allowance for equity fundsAllowance for equity funds34 50 90 122 
Interest and dividend incomeInterest and dividend income18 17 65 57 
Gains on marketable securities, netGains on marketable securities, net294 1,797 1,142 2,407 
Other, netOther, net8 36 64 61 
Total income before income tax (benefit) expense and equity lossTotal income before income tax (benefit) expense and equity loss$1,675 $2,967 $4,189 $4,619 

Interest expense:
PacifiCorp$110 $107 $322 $319 
MidAmerican Funding81 79 237 238 
NV Energy51 56 154 171 
Northern Powergrid33 34 98 97 
BHE Pipeline Group33 15 111 44 
BHE Transmission39 38 117 111 
BHE Renewables39 41 119 125 
HomeServices1 1 3 9 
BHE and Other(1)
144 133 432 376 
Total interest expense$531 $504 $1,593 $1,490 
Earnings on common shares:
PacifiCorp$333 $286 $728 $629 
MidAmerican Funding373 337 728 695 
NV Energy282 249 416 367 
Northern Powergrid83 26 162 172 
BHE Pipeline Group144 78 627 321 
BHE Transmission65 58 184 173 
BHE Renewables163 162 360 395 
HomeServices102 177 321 246 
BHE and Other(1)
351 1,469 580 1,630 
Total earnings on common shares$1,896 $2,842 $4,106 $4,628 



29

As of
Three-Month Periods Nine-Month Periods September 30,December 31,
Ended September 30, Ended September 30,20212020
2017 2016 2017 2016
Operating income:       
Assets:Assets:
PacifiCorp$467
 $445
 $1,150
 $1,108
PacifiCorp$28,230 $26,862 
MidAmerican Funding288
 284
 531
 524
MidAmerican Funding25,038 23,530 
NV Energy393
 394
 682
 656
NV Energy15,105 14,501 
Northern Powergrid81
 90
 308
 373
Northern Powergrid9,043 8,782 
BHE Pipeline Group65
 68
 328
 320
BHE Pipeline Group19,993 19,541 
BHE Transmission86
 81
 236
 35
BHE Transmission9,383 9,208 
BHE Renewables157
 157
 256
 233
BHE Renewables11,766 12,004 
HomeServices79
 87
 191
 179
HomeServices5,065 4,955 
BHE and Other(1)
8
 (21) (38) (36)
BHE and Other(1)
7,931 7,933 
Total operating income1,624

1,585
 3,644

3,392
Interest expense(464) (460) (1,379) (1,401)
Capitalized interest14
 14
 34
 128
Allowance for equity funds24
 17
 59
 147
Interest and dividend income32
 39
 85
 93
Other, net2
 15
 24
 26
Total income before income tax expense and equity income$1,232

$1,210
 $2,467

$2,385
Total assetsTotal assets$131,554 $127,316 

(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Interest expense:       
PacifiCorp$95
 $95
 $285
 $286
MidAmerican Funding59
 55
 177
 164
NV Energy57
 60
 173
 190
Northern Powergrid34
 33
 98
 105
BHE Pipeline Group11
 13
 33
 39
BHE Transmission45
 40
 125
 114
BHE Renewables51
 51
 153
 148
HomeServices1
 1
 3
 2
BHE and Other(1)
111
 112
 332
 353
Total interest expense$464
 $460
 $1,379

$1,401
 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating revenue by country:
United States$6,499 $5,773 $17,700 $14,086 
United Kingdom277 246 857 733 
Canada180 174 537 512 
Philippines and other12 — 19 1 
Total operating revenue by country$6,968 $6,193 $19,113 $15,332 
Income before income tax (benefit) expense and equity loss by country:
United States$1,511 $2,839 $3,699 $4,220 
United Kingdom107 82 343 250 
Canada49 44 134 130 
Philippines and other8 2 13 19 
Total income before income tax (benefit) expense and equity loss by country$1,675 $2,967 $4,189 $4,619 
Operating revenue by country:       
United States$4,869
 $4,697
 $12,793
 $12,185
United Kingdom221
 220
 685
 748
Canada182
 170
 506
 313
Philippines and other11
 5
 19
 8
Total operating revenue by country$5,283
 $5,092
 $14,003
 $13,254
Income before income tax expense and equity income by country:       
United States$1,113
 $1,089
 $2,065
 $1,945
United Kingdom49
 74
 213
 284
Canada47
 43
 127
 114
Philippines and other23
 4
 62
 42
Total income before income tax expense and equity income by country$1,232
 $1,210
 $2,467
 $2,385




 As of
 September 30, December 31,
 2017 2016
Assets:   
PacifiCorp$23,578
 $23,563
MidAmerican Funding19,019
 17,571
NV Energy14,344
 14,320
Northern Powergrid7,280
 6,433
BHE Pipeline Group4,958
 5,144
BHE Transmission9,182
 8,378
BHE Renewables7,492
 7,010
HomeServices2,834
 1,776
BHE and Other(1)
2,367
 1,245
Total assets$91,054
 $85,440

(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.


The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 20172021 (in millions):
BHE Pipeline Group
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE TransmissionBHE RenewablesHomeServices
Total
 
December 31, 2020$1,129 $2,102 $2,369 $1,000 $1,803 $1,551 $95 $1,457 $11,506 
Acquisitions— — — — 11 — — 59 70 
Foreign currency translation— — — (10)— 6 — — (4)
September 30, 2021$1,129 $2,102 $2,369 $990 $1,814 $1,557 $95 $1,516 $11,572 

30
         BHE Pipeline Group        
   MidAmerican Funding NV Energy Northern Powergrid  BHE Transmission BHE Renewables HomeServices  
 PacifiCorp        Total
                  
December 31, 2016$1,129
 $2,102
 $2,369
 $930
 $75
 $1,470
 $95
 $840
 $9,010
Acquisitions—
 —
 —
 —
 —
 —
 —
 522
 522
Foreign currency translation—
 —
 —
 56
 —
 114
 —
 —
 170
Other—
 —
 —
 —
 (2) —
 —
 —
 (2)
September 30, 2017$1,129
 $2,102
 $2,369
 $986
 $73
 $1,584
 $95
 $1,362
 $9,700



Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 2.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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.


The Company isBerkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) Limitedplc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of AltaLinkBHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, twofive interstate natural gas pipeline companies, one of which owns 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 selling power generated frominvesting in wind, solar, wind, geothermal and hydroelectric sources under long-term contracts,projects, the second largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. 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 MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.


31

Results of Operations for the Third Quarter and First Nine Months of 20172021 and 20162020


Overview


Net incomeOperating revenue and earnings on common shares for the Company's reportable segments isare summarized as follows (in millions):
Third QuarterFirst Nine Months
20212020Change20212020Change
Operating revenue:
PacifiCorp$1,491 $1,479 $12 1 %$4,031 $3,829 $202 5 %
MidAmerican Funding966 812 154 19 2,726 2,114 612 29 
NV Energy1,085 1,042 43 4 2,443 2,359 84 4 
Northern Powergrid277 246 31 13 857 733 124 17 
BHE Pipeline Group785 264 521 *2,584 890 1,694 *
BHE Transmission185 175 10 6 547 516 31 6 
BHE Renewables316 309 7 2 773 731 42 6 
HomeServices1,743 1,742 1 — 4,738 3,828 910 24 
BHE and Other120 124 (4)(3)414 332 82 25 
Total operating revenue$6,968 $6,193 $775 13 %$19,113 $15,332 $3,781 25 %
Earnings on common shares:
PacifiCorp$333 $286 $47 16 %$728 $629 $99 16 %
MidAmerican Funding373 337 36 11 728 695 33 5 
NV Energy282 249��33 13 416 367 49 13 
Northern Powergrid83 26 57 *162 172 (10)(6)
BHE Pipeline Group144 78 66 85 627 321 306 95 
BHE Transmission65 58 7 12 184 173 11 6 
BHE Renewables(1)
163 162 1 1 360 395 (35)(9)
HomeServices102 177 (75)(42)321 246 75 30
BHE and Other351 1,469 (1,118)(76)580 1,630 (1,050)(64)
Total earnings on common shares$1,896 $2,842 $(946)(33)%$4,106 $4,628 $(522)(11)%
 Third Quarter First Nine Months
 2017 2016 Change 2017 2016 Change
Net income attributable to BHE shareholders:               
PacifiCorp$263
 $254
 $9
 4 % $618
 $596
 $22
 4 %
MidAmerican Funding383
 318
 65
 20
 616
 518
 98
 19
NV Energy223
 222
 1
 —
 347
 319
 28
 9
Northern Powergrid39
 60
 (21) (35) 174
 228
 (54) (24)
BHE Pipeline Group35
 36
 (1) (3) 183
 175
 8
 5
BHE Transmission58
 57
 1
 2
 171
 173
 (2) (1)
BHE Renewables89
 98
 (9) (9) 194
 142
 52
 37
HomeServices45
 49
 (4) (8) 107
 105
 2
 2
BHE and Other(67) (58) (9) (16) (212) (194) (18) (9)
Total net income attributable to BHE shareholders$1,068
 $1,036
 $32
 3
 $2,198
 $2,062
 $136
 7


(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.
Net income attributable to BHE shareholders increased $32
*    Not meaningful

Earnings on common shares decreased $946 million for the third quarter of 20172021 compared to 20162020. The third quarter of 2021 included a pre-tax unrealized gain of $296 million ($253 million after-tax) compared to a pre-tax unrealized gain in the third quarter of 2020 of $1,787 million ($1,299 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the third quarter of 2021 was $1,643 million, an increase of $100 million, or 6%, compared to adjusted earnings on common shares in the third quarter of 2020 of $1,543 million.
Earnings on common shares decreased $522 million for the first nine months of 2021 compared to 2020. The first nine months of 2021 included a pre-tax unrealized gain of $1,126 million ($855 million after-tax) compared to a pre-tax unrealized gain in the first nine months of 2020 of $2,402 million ($1,746 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first nine months of 2021 was $3,251 million, an increase of $369 million, or 13%, compared to adjusted earnings on common shares in the first nine months of 2020 of $2,882 million.


32

The decreases in earnings on common shares for the third quarter and for the first nine months of 2021 compared to 2020 were primarily due to the following:
PacifiCorp's net•The Utilities' earnings increased $116 million for the third quarter and $181 million for the first nine months of 2021 compared to 2020, reflecting higher electric utility margin, favorable income increased $9 million primarily due totax expense, from higher gross marginsPTCs recognized and the impacts of $30 million, excluding the impact of demand side management program revenue (offset in operating expense),ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense. Electric retail customer volumes increased 4.8% for the first nine months of $7 million,2021 compared to 2020, primarily from additional plant placed in-service. Gross margins increased due to higher retail customer volumes, lower coal costs, lower natural gas-fueled generation, and higher wheeling revenue, partially offset by higher purchased electricity costs, lower average retail rates and lower wholesale revenue from lower volumes. Retail customer volumes increased 2.1% due to impactsusage, the favorable impact of weather on residential customers primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah and an increase in the average number of residentialcustomers;
•Northern Powergrid's earnings increased $57 million for the third quarter and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon and lower industrial usage in Utah and Oregon.



MidAmerican Funding's net income increased $65decreased $10 million for the first nine months of 2021 compared to 2020, primarily due to higher recognized production tax credits of $45 million due to higher generation from wind-powered facilities placed in-service in the second half of 2016, higher electric gross margins of $7 million, excluding the impact of demand side management program revenue (offset in operating expense), and lower depreciation and amortization of $7 million substantially from changes in accruals for Iowa regulatory arrangements. Electric gross margins increased due to higher recoveries through bill riders and higher transmission revenue, partially offset by lower wholesale revenue from lower sales volumes and prices.
Northern Powergrid's net income decreased $21 million largely due to $17 million of deferred income tax benefits reflectedcharges ($35 million in the third quarter of 2016 due2020 and $109 million in second quarter 2021) related to a 1% reductionenacted increases in the United Kingdom corporate income tax rate and higher pension expense of $13distribution revenue;
•BHE Pipeline Group's earnings increased $66 million and lower distribution revenue of $7 million, partially offset by $19 million of asset provisions recognized infor the third quarter of 2016 at the CE Gas business. Distribution revenue decreased mainly due to lower tariff rates and units distributed.
BHE Renewables' net income decreased $9 million mainly due to make-whole payments associated with the early redemptions of certain project debt.
HomeServices' net income decreased $4 million primarily due to lower earnings from brokerage and mortgage businesses.
BHE and Other net loss increased $9 million primarily due to lower federal income tax credits recognized on a consolidated basis, higher consolidated deferred state income tax expense due to an increase in the Illinois enacted tax rate and unfavorable results of $8 million at MidAmerican Energy Services, LLC, partially offset by lower other operating costs.

Net income attributable to BHE shareholders increased $136$306 million for the first nine months of 20172021 compared to 20162020, largely due to $74 million and $247 million, respectively, of incremental earnings from BHE GT&S, acquired in November 2020. In addition, earnings for the first nine months increased from the effects of higher margins on natural gas sales and higher transportation revenue at Northern Natural Gas, largely due to the following:
PacifiCorp's net income increased $22 million primarily due to higher gross margins of $71 million, excluding the impact of demand side management program revenue (offset in operating expense), partially offset by higher depreciation and amortization of $22 million from additional plant placed in-service and higher property and other taxes. Gross margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue from higher short-term market prices and volumes and higher wheeling revenue, partially offset by higher purchased electricity costs and lower average retail rates. Retail customer volumes increased 2.4% due tofavorable impacts of the February 2021 polar vortex weather primarily on residential customers in Oregon, Washington and Utah, higher commercial usage primarily in Utah and Oregon, an increase in the average number of residential and commercial customers primarily in Utah and Oregon and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho.event;
MidAmerican Funding's net income increased $98 million primarily due to higher recognized production tax credits of $71 million due to higher generation from wind-powered facilities placed in-service in the second half of 2016 and higher electric gross margins of $60 million, excluding the impact of demand side management program revenue (offset in operating expense), partially offset by higher depreciation and amortization of $31 million, primarily due to accruals for Iowa regulatory arrangements and the increase in wind-powered generating facilities, and higher operating expenses. Electric gross margins increased due to higher wholesale revenue from higher sales volumes and prices, higher recoveries through bill riders, higher retail customer volumes and higher transmission revenue, partially offset by higher coal-fueled generation and purchased power costs. Retail customer volumes increased 1.5% due to industrial growth net of lower residential and commercial volumes from milder temperatures.
NV Energy's net income increased $28•BHE Renewables' earnings decreased $35 million for the first nine months of 20172021 compared to 20162020, primarily due to higher electric gross margins of $25 million, excluding the impact of energy efficiency program revenue (offset in operating expense), and lower interest expense of $17 million on lower deferred charges and from lower rates on outstanding debt balances. Electric gross margins increased due to higher customer usagetax equity investment earnings from the impacts ofFebruary 2021 polar vortex weather an increase in the average number of customers, customer usage patterns and an increase in transmission revenues.
Northern Powergrid's net income decreased $54 million largely due to the stronger United States dollar of $19 million, higher pension expense of $21 million, lower distribution revenue of $17 million and $17 million of deferred income tax benefits reflected in the third quarter of 2016 due to a 1% reduction in the United Kingdom corporate income tax rate,event, partially offset by $19 million of asset provisions recognized in the third quarter of 2016 at the CE Gas business. Distribution revenue decreased due to lower units distributed, the recovery in 2016 of the December 2013 customer rebate and unfavorable movements in regulatory provisions, partially offset by higher tariff rates.
BHE Pipeline Group’s net income increased $8 million due to a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River and higher transportation revenues at Northern Natural Gas, partially offset by lower transportation revenues at Kern River and higher operating expenses at Northern Natural Gas.


BHE Transmission's net income decreased $2 million from lower earnings at BHE U.S. Transmission of $4 million from lower equity earnings at Electric Transmission Texas, LLC due to the impacts of new rates effective in March 2017, partially offset by higher earnings at AltaLink of $2 million primarily due to the impacts of additional assets placed in-service partially offset by lower recoveries and decreases in contingent liabilities.
BHE Renewables' net income increased $52 million mainly due to favorable earnings from tax equity investmentsinvestment projects reaching commercial operation additional wind and solar capacity placed in-service, higher generation at the Solar Star projects due to transformer related forced outages in 2016 and higher production atoperating revenue from owned renewable energy projects;
•HomeServices' earnings decreased $75 million for the Casecnan project duethird quarter and increased $75 million for the first nine months of 2021 compared to higher rainfall, partially offset by make-whole payments associated with the early redemptions of certain project debt.
HomeServices' net income increased $2 million primarily due to higher earnings at franchise businesses, partially offset by lower earnings at brokerage and mortgage businesses.
BHE and Other net loss increased $18 million2020, primarily due to lower federal income tax credits recognized onearnings from mortgage services due to a consolidated basis,decrease in refinance activity. In addition, earnings for the first nine months was favorably impacted by higher consolidated deferred state income tax expenseearnings from brokerage services due to an increase in the Illinois enacted tax rateclosed transaction volume and unfavorable results of $8 million at MidAmerican Energy Services, LLC, partially offset by lower interest expensean increase in mortgage services earnings due to redemptionsan unfavorable 2020 contingent earn-out remeasurement; and
•BHE and Other's earnings decreased $1,118 million for the third quarter and $1,050 million for the first nine months of junior subordinated debentures2021 compared to 2020, mainly due to $1,046 million and lower consolidated deferred state income tax expense due to$891 million, respectively, of unfavorable changes in the tax statusafter-tax unrealized position of the Company's investment in BYD Company Limited, and dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries.subsidiaries of Berkshire Hathaway in October 2020.


Reportable Segment Results


Operating revenue and operating income for the Company's reportable segments are summarized as follows (in millions):
PacifiCorp
 Third Quarter First Nine Months
 2017 2016 Change 2017 2016 Change
Operating revenue:               
PacifiCorp$1,430
 $1,434
 $(4) — % $3,956
 $3,919
 $37
 1 %
MidAmerican Funding815
 797
 18
 2
 2,170
 2,008
 162
 8
NV Energy1,047
 987
 60
 6
 2,384
 2,309
 75
 3
Northern Powergrid221
 220
 1
 —
 685
 748
 (63) (8)
BHE Pipeline Group193
 201
 (8) (4) 700
 704
 (4) (1)
BHE Transmission182
 169
 13
 8
 506
 309
 197
 64
BHE Renewables283
 273
 10
 4
 647
 582
 65
 11
HomeServices961
 820
 141
 17
 2,502
 2,152
 350
 16
BHE and Other151
 191
 (40) (21) 453
 523
 (70) (13)
Total operating revenue$5,283
 $5,092
 $191
 4
 $14,003
 $13,254
 $749
 6
Operating income:               
PacifiCorp$467
 $445
 $22
 5 % $1,150
 $1,108
 $42
 4 %
MidAmerican Funding288
 284
 4
 1
 531
 524
 7
 1
NV Energy393
 394
 (1) —
 682
 656
 26
 4
Northern Powergrid81
 90
 (9) (10) 308
 373
 (65) (17)
BHE Pipeline Group65
 68
 (3) (4) 328
 320
 8
 3
BHE Transmission86
 81
 5
 6
 236
 35
 201
 *
BHE Renewables157
 157
 —
 —
 256
 233
 23
 10
HomeServices79
 87
 (8) (9) 191
 179
 12
 7
BHE and Other8
 (21) 29
 * (38) (36) (2) (6)
Total operating income$1,624
 $1,585
 $39
 2
 $3,644
 $3,392
 $252
 7

*    Not meaningful



PacifiCorp


Operating revenue decreased $4increased $12 million for the third quarter of 20172021 compared to 20162020, primarily due to lowerhigher retail revenue of $8 million partially offset byand higher wholesale and other revenue of $4 million. Retail revenue decreasedincreased due to lower average rates and lower demand side management program revenue (offset in operating expense), primarily driven by the establishmenthigher customer volumes of the Utah Sustainable Transportation and Energy Plan program,$28 million, partially offset by higher customer volumes.price impacts of $20 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to impacts of weather on residential customers, primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah, and an increase in the average number of residentialcustomers and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon.higher customer usage. Wholesale and other revenue increased primarily due to higher wheeling revenue and REC revenues,sales, partially offset by lower wholesale sales volumes.$27 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.


Operating incomeEarnings increased $22$47 million for the third quarter of 20172021 compared to 20162020, primarily due to lower operating expensesoperations and maintenance expense of $23$65 million, favorable income tax expense, from the impacts of ratemaking and higher gross marginsPTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility margin of $9$6 million, partially offset by higher depreciation and amortization expense of $7 million from additional plant placed in-service. Operating expenses decreased due to a decrease in demand side management program expense (offset in operating revenue) of $21$38 million and lower pension expense. Gross marginsallowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily due to higher net deferrals of incurreddeferred net power costs in accordance with established adjustment mechanisms lower coal costs and lower natural gas-fueled generation,the higher retail and wheeling revenue, partially offset by higher purchased electricitypower and thermal generation costs fromand higher priceswheeling expenses. Operations and volumes.maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires 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. 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.



33

Operating revenue increased $37$202 million for the first nine months of 20172021 compared to 20162020, primarily due to higher retail revenue of $152 million and higher wholesale and other revenue of $31 million and higher retail revenue of $6$50 million. Wholesale and other revenue increased due to higher wholesale revenue from higher short-term market prices and sales volumes and higher wheeling and REC revenues. Retail revenue increased due to higher customer volumes of $176 million, partially offset by price impacts of $24 million from lower average rates and lower demand side management program revenue (offset in operating expense), primarily driven by the establishment of the Utah Sustainable Transportation and Energy Plan program.due to certain general rate case orders. Retail customer volumes increased 2.4%4.4%, primarily due to impacts of weather, primarily on residential customers in Oregon, Washington and Utah, higher commercialcustomer usage, primarily in Utah and Oregon, an increase in the average number of residentialcustomers and commercial customers,the favorable impact of weather. Wholesale and other revenue increased primarily in Utahdue to higher wheeling revenue, wholesale volumes and Oregon, and higher industrial usage in the eastern service territory,REC sales, partially offset by lower residential usage across$34 million from the service territory, lower industrial usageOregon RAC settlement (offset in Oregon and lower irrigation usage primarilydepreciation expense) recognized in Oregon and Idaho.2020.


Operating incomeEarnings increased $42$99 million for the first nine months of 20172021 compared to 20162020, primarily due to higher utility margin of $131 million, favorable income tax expense, from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, and lower operating expensesoperations and maintenance expense of $45 million and higher gross margins of $26$48 million, partially offset by higher depreciation and amortization expense of $22 million from additional plant placed in-service and higher property taxes. Operating expenses decreased due to a decrease in demand side management program expense (offset in operating revenue) of $44$115 million and lower pension expense, partially offset by higher injuryallowances for equity and damage expenses,borrowed funds used during construction of $53 million. Utility margin increased primarily due to a prior year accrual for insurance proceedsthe higher retail, wholesale and current year settlements,wheeling revenues and higher labor costs related to storm damage restoration. Gross margins were higher due to the increase in operating revenue, higher net deferrals of incurreddeferred net power costs in accordance with established adjustment mechanisms, lower natural gas-fueled generation and lower coal costs, partially offset by higher purchased electricitypower and thermal generation costs fromand higher volumeswheeling expenses. Operations and prices.maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires 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. 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.


MidAmerican Funding


Operating revenue increased $18$154 million for the third quarter of 20172021 compared to 20162020, primarily due to higher electric operating revenue of $15 million from higher retail revenue of $29 million and lower wholesale and other revenue of $14 million. Electric retail revenue increased $38 million from higher recoveries through bill riders (substantially offset in cost of sales, operating expense and income tax expense) and $5 million from non-weather usage and rate factors, including higher industrial sales volumes, partially offset by $14 million from the impact of milder temperatures in 2017. Electric retail customer volumes increased 0.4% from industrial growth, partially offset by the unfavorable impact of temperatures. Electric wholesale and other revenue decreased due to lower wholesale volumes of $14 million and lower wholesale prices of $6 million, partially offset by higher transmission revenue of $6 million.

Operating income increased $4 million for the third quarter of 2017 compared to 2016 due to higher electric gross margins of $15 million due to the increase in operating revenue and lower depreciation and amortization of $7 million, partially offset by higher operating expenses. The decrease in depreciation and amortization reflects lower accruals for Iowa regulatory arrangements and a reduction of $9 million from lower depreciation rates implemented in December 2016, partially offset by wind generation and other plant placed in-service. Operating expenses increased primarily due to higher demand side management program expense (offset in operating revenue) of $8 million and higher generation maintenance costs.



Operating revenue increased $162 million for the first nine months of 2017 compared to 2016 due to higher electric operating revenue of $105$126 million and higher natural gas operating revenue of $55$30 million. Electric operating revenue increased due to higher retail revenue of $67 million and higher wholesale and other revenue of $53$59 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $43 million (largely offset in cost of sales) and higher customer volumes of $24 million. Electric retail revenuecustomer volumes increased 5.6% due to increased usage of $52 million.certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased mainly due primarily to higher average wholesale per-unit prices of $34 million and higher wholesale volumes of $34 million, higher transmission revenue of $11 million and higher wholesale prices of $6$17 million. Electric retail revenue increased $47 million from higher recoveries through bill riders (substantially offset in cost of sales, operating expense and income tax expense) and $33 million from non-weather usage and rate factors, including higher industrial sales volumes, partially offset by $28 million from the impact of milder temperatures in 2017. Electric retail customer volumes increased 1.5% from industrial growth, partially offset by the unfavorable impact of temperatures. 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 $59$24 million (offset in cost of sales).

Earnings increased $36 million for the third quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $78 million and lower operations and maintenance expense of $12 million, mainly due to 2020 costs associated with storm restoration activities, partially offset by higher depreciation and amortization expense of $39 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms.

Operating revenue increased $612 million for the first nine months of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $344 million and higher electric operating revenue of $268 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 $345 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event. Electric operating revenue increased due to higher demand side management programretail revenue (offset in operating expense) of $3$157 million and 1.7% higher wholesale and other revenue of $111 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $91 million (largely offset in cost of sales), higher customer volumes of $59 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes partially offset by 6.2% lower retail sales volumes.increased 6.5% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased due to higher wholesale volumes of $64 million and higher average wholesale per-unit prices of $42 million.


Operating incomeEarnings increased $7$33 million for the first nine months of 20172021 compared to 20162020, primarily due to higher electric gross marginsutility margin of $75$117 million and higher natural gas gross margins of $3 million,a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $31$104 million, higher propertyoperations and other taxesmaintenance expense of $6$18 million and higher operating expenses.lower allowances for equity and borrowed funds of $12 million. Electric gross margins were higherutility margin increased primarily due to the increase in operating revenue,higher retail and wholesale revenues, partially offset by higher coal-fueledthermal generation and higher purchased power costs. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service as well as higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities. The increase in depreciation and amortization reflects wind generation and other plantexpense was primarily due to additional assets placed in-service andas well as from the impacts of certain regulatory mechanisms. The favorable income tax benefit was from higher accruals for Iowa regulatory arrangements,PTCs recognized due to new wind-powered generating facilities placed in-service, partially offset by a reductionthe impacts of $26ratemaking.

34

On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by the IUB in MidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense of $13 million fromfor the third quarter and $39 million for the first nine months of 2021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower depreciation rates implemented in December 2016. Operating expenses increased primarily due to higher demand side management program expense (offsetyears 2021 through 2023 than would have been recognized absent the order. The annual amount of the deferral for 2021 will be recognized in operating revenue) of $17 million and higher generation maintenance costs.the fourth quarter.


NV Energy


Operating revenue increased $60$43 million for the third quarter of 20172021 compared to 20162020 due to higher electric operating revenue, which increased primarily due to higher retail revenue of $58 million and higher transmission revenue of $4 million. Electric retail revenue increased due to $115 million from higherfully-bundled energy rates primarily from energy costs (offset in cost of sales), $25 of $80 million from higher distribution only service revenue and impact fees received due to customers purchasing energy from alternative providers and becoming distribution only service customers, $5 million from an increase in the average number of customers, and $4 million higher customer usage mainly from the impacts of weather, partially offset by $73lower base tariff general rates of $27 million from lower commercialat Nevada Power and industrial revenue, mainly from customers purchasing energy from alternative providers, $10 million of lower energy efficiency program revenue (offseta favorable regulatory decision in operating expense) and $9 million from a refinement of the unbilled revenue estimate.2020. Electric retail customer volumes including distribution only service customers, increased 3.8% compared3.9%, primarily due to 2016.higher customer usage, partially offset by the unfavorable impact of weather.


Operating income decreased $1Earnings increased $33 million for the third quarter of 20172021 compared to 2016 due to lower electric gross margins of $9 million offset by lower operating expenses of $8 million2020, primarily due to lower energy efficiency programoperations and maintenance expense (offset inof $51 million, lower income tax expense from the impacts of ratemaking and lower interest expense of $5 million, partially offset by lower electric operating revenue).utility margin of $39 million and higher depreciation and amortization expense of $9 million. Electric gross margins were lower due to higher energy costs of $69 millionutility margin decreased primarily due to lower net deferred power costs,base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by thean increase in electric operating revenue.the average number of customers. Operations and maintenance expense decreased primarily due to lower earnings sharing at Nevada Power and lower regulatory deferrals and amortizations. 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 increased $75$84 million for the first nine months of 20172021 compared to 20162020, primarily due to higher electric operating revenue of $89$92 million, partially offset by lower natural gas operating revenue of $15$8 million. Electric operating revenue increased primarily due to higher retail revenue of $81 million and higher transmission revenue of $9 million. Electric retail revenue increased due to $130 million from higherfully-bundled energy rates primarily from energy costs (offset in cost of sales), $36 of $153 million, higher retail customer volumes, price impacts from higher distribution only service revenuechanges in sales mix and impact fees received due to customers purchasing energy from alternative providers and becoming distribution only service customers, $18 million from an increase in the average number customers and $11 million higher customer usage mainly from the impacts of weather,customers, partially offset by $93lower base tariff general rates of $51 million from lower commercialat Nevada Power and industrial revenue, mainly from customers purchasing energy from alternative providers, and $23 million of lower energy efficiency program revenue (offseta favorable regulatory decision in operating expense).2020. Electric retail customer volumes including distribution only service customers, increased 2.4% compared4.2%, primarily due to 2016.higher customer usage and the favorable impact of weather. Natural gas operating revenue decreased primarily due to a lower energy rates, partially offset by higher customer usage.average per-unit cost of natural gas sold (offset in cost of sales).


Operating incomeEarnings increased $26$49 million for the first nine months of 20172021 compared to 2016 due to lower operating expenses of $23 million2020, primarily due to lower energy efficiency programoperations and maintenance expense (offsetof $72 million, lower income tax expense from the impacts of ratemaking, lower interest expense of $17 million, lower pension costs of $10 million, higher interest and dividend income of $8 million and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower electric operating revenue)utility margin of $61 million and higher electric gross marginsdepreciation and amortization expense of $2$34 million. Electric gross margins were higherutility margin decreased primarily due to the increaselower base tariff general rates at Nevada Power and a favorable regulatory decision in electric operating revenue,2020, partially offset by higher energy costsretail customer volumes, price impacts from changes in sales mix and an increase in the average number of $87 million. Energy costs increasedcustomers. Operations and maintenance expense decreased primarily due to a higher average costlower regulatory deferrals and amortizations and lower earnings sharing at Nevada Power. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of fuel for generation of $62 million, lower net deferred powerdecommissioning costs of $23 million and higher purchased power costs of $3 million.additional assets placed in-service.




Northern Powergrid


Operating revenue increased $1$31 million for the third quarter of 20172021 compared to 20162020, primarily due to lower$17 million from the weaker United States dollar and higher distribution revenue of $7$17 million, partially offset bymainly from 4.1% higher smart metering revenueunits distributed of $6 million. Distribution revenue decreased mainly due to lower$10 million and increased tariff rates of $4 million and lower units distributed of $2$8 million. Operating income decreased $9

Earnings increased $57 million for the third quarter of 20172021 compared to 2016 due to higher pension expense of $13 million, mainly2020, primarily due to a settlement loss recognizeddeferred income tax charge in July 2020 of $35 million related to the third quarterUnited Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as a result ofhad previously been announced, and the level of lump sum plan withdrawals, higher depreciation of $7 million from additional assets placed in-service and higher distribution costs of $4 million, partially offset by $19 million of asset provisions recognized in the third quarter of 2016 at the CE Gas business.revenue.


Operating revenue decreased $63increased $124 million for the first nine months of 20172021 compared to 20162020, primarily due to $69 million from the strongerweaker United States dollar of $66 million and lowerhigher distribution revenue of $17$56 million, partially offset bymainly from increased tariff rates of $27 million and 4.5% higher smart metering revenue of $18 million. Distribution revenue decreased due to lower units distributed of $14 million, the recovery in 2016 of the December 2013 customer rebate of $11 million and unfavorable movements in regulatory provisions of $5 million, partially offset by higher tariff rates of $11$26 million. Operating income

35

Earnings decreased $65$10 million for the first nine months of 20172021 compared to 20162020, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the stronger United States dollar of $33 million, higher pension expense of $23 million, mainly dueKingdom corporate income tax rate from 19% to the 2017 settlement loss recognized, higher depreciation of $21 million from additional assets placed in service and higher distribution costs of $7 million,25% effective April 1, 2023, partially offset by $19the higher distribution revenue, a deferred income tax charge in July 2020 of $35 million of asset provisions recognized inrelated to the third quarter of 2016 atUnited Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and $11 million from the CE Gas business.weaker United States dollar.


BHE Pipeline Group


Operating revenue decreased $8increased $521 million for the third quarter of 20172021 compared to 20162020, primarily due to $516 million of incremental revenue at BHE GT&S, acquired in November 2020, and higher transportation revenue of $23 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $19 million at Northern Natural Gas primarily due to lower transportation revenues at Kern River, partially offset by higher transportation revenues at Northern Natural Gas. Operating income decreased $3volumes.

Earnings increased $66 million for the third quarter of 20172021 compared to 20162020, primarily due to lower transportation revenues$74 million of incremental earnings at BHE GT&S and higher earnings of $16 million at Kern River andfrom the higher operating expensestransportation revenue, partially offset by lower earnings of $25 million at Northern Natural Gas, partially offset byprimarily due to the lower depreciation expense and higher transportation revenues at Northern Natural Gas.revenue.


Operating revenue decreased $4increased $1,694 million for the first nine months of 20172021 compared to 20162020, primarily due lower transportation revenuesto $1,563 million of incremental revenue at Kern River, partially offset byBHE GT&S, higher gas sales of $15$77 million relatedand higher transportation revenue of $49 million at Northern Natural Gas, each due to system balancing activitiesthe favorable impacts of the February 2021 polar vortex weather event, higher gas sales at Northern Natural Gas of $33 million (largely offset in cost of sales) and higher transportation revenuesrevenue of $25 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $69 million at Northern Natural Gas. Operating incomeGas primarily due to lower volumes.

Earnings increased $8$306 million for the first nine months of 20172021 compared to 20162020, primarily due to a reduction in expenses and regulatory liabilities related to the impact$247 million of an alternative rate structure approved by the FERCincremental earnings at Kern River andBHE GT&S, higher transportation revenues at Northern Natural Gas, partially offset by higher operating expensesearnings of $39 million at Northern Natural Gas and lower transportation revenuesfavorable earnings of $18 million at Kern River.

BHE Transmission

Operating revenue increased $13 million forRiver from the third quarter of 2017 compared to 2016higher transportation revenue. Northern Natural Gas' improved performance was primarily due to the weaker United States dollar of $7 millionhigher gross margin on gas sales and higher costs recovered in operating revenue. Operating income increased $5 million for the third quarter of 2017 compared to 2016 primarilytransportation revenue, each due to the weaker United States dollarfavorable impacts of $4 million.

Operating revenue increased $197 million for the first nine months of 2017 compared to 2016 primarily due to a one-time reduction of $200 million from the 2015-2016 GTA decision received in May 2016 at AltaLink, $10 million from additional assets placed in service and the weaker United States dollar of $9 million,February 2021 polar vortex weather event, partially offset by the lower costs recovered in operating revenue. Operating income increased $201 million for the first nine months of 2017 comparedtransportation revenue due primarily to 2016 primarily due to the higher operating revenue from the 2015-2016 GTA decision that required AltaLink to refund $200 million to customers in 2016 through reduced monthly billings for the change from receiving cash during construction for the return on construction work-in-progress 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. The refund was offset with higher capitalized interest and allowance for equity funds. Operating income was also favorably impacted $6 million by the weaker United States dollar.lower volumes.


BHE RenewablesTransmission


Operating revenue increased $10 million for the third quarter of 20172021 compared to 20162020, primarily due to additional wind$10 million from the stronger United States dollar and solar capacity placed in-servicehigher revenue from the Montana-Alberta Tie-Line of $17$5 million, partially offset by lower geothermal revenues of $6 million due to unfavorable pricing and lower capacity revenues. Operating income was unchanged for the third quarter of 2017 compared to 2016 as higher costs associated with the additional capacity placed in-service offset the increased revenues.



Operating revenue increased $65 million for the first nine months of 2017 compared to 2016 due to additional wind and solar capacity placed in-service of $45 million, higher generation at the Solar Star projects of $29 million due to transformer related forced outages in 2016 and higher production at the Casecnan project of $10 million due to higher rainfall, partially offset by lower generation at the Topaz project of $11 million mainly due to a scheduled maintenance outage and lower generation of $7 million at the existing wind projects due to a lower wind resource. Operating income increased $23 million for the first nine months of 2017 compared to 2016 due to the increase in operating revenue, partially offset by higher operating expense of $24 million and higher depreciation and amortization of $17 million, each primarily due to the additional wind and solar capacity placed in-service. Operating expense also increased from the scope and timing of maintenance at certain geothermal plants. The change in depreciation and amortization reflects a reduction of $6 million from the extension of the useful life of certain wind-generating facilities from 25 years to 30 years effective January 2017.

HomeServices

Operating revenue increased $141 million for the third quarter of 2017 compared to 2016 due to an increase from acquired businesses totaling $139 million. Operating income decreased $8 million for the third quarter of 2017 compared to 2016 primarily due to lower earnings from brokerage businesses, mainly due to higher operating expenses, and lower mortgage revenue.

Operating revenue increased $350 million for the first nine months of 2017 compared to 2016 primarily due to an increase from acquired businesses totaling $279 million and a 3.8% increase in average home sales prices for existing businesses. Operating income increased $12 million for the first nine months of 2017 compared to 2016 primarily due to higher earnings from franchise businesses, mainly due to a favorable settlement and a gain on the collection of notes receivable, partially offset by lower earnings from brokerage businesses, mainly due to higher operating expenses, and lower mortgage revenue.

BHE and Other

Operating revenue decreased $40 million for the third quarter of 2017 compared to 2016 due to lower electricity and natural gas volumes and rates at MidAmerican Energy Services, LLC. Operating income improved $29 million for the third quarter of 2017 compared to 2016 due to lower operating expenses, partially offset by lower margins of $8 million at MidAmerican Energy Services, LLC.

Operating revenue decreased $70 million for the first nine months of 2017 compared to 2016 due to lower electricity and natural gas volumes and rates at MidAmerican Energy Services, LLC. Operating loss increased $2 million for the first nine months of 2017 compared to 2016 due to lower margins of $9 million at MidAmerican Energy Services, LLC, partially offset by lower operating expenses.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):
 Third Quarter First Nine Months
 2017 2016 Change 2017 2016 Change
                
Subsidiary debt$354
 $345
 $9
 3 % $1,045
 $1,042
 $3
 — %
BHE senior debt and other106
 101
 5
 5
 317
 305
 12
 4
BHE junior subordinated debentures4
 14
 (10) (71) 17
 54
 (37) (69)
Total interest expense$464
 $460
 $4
 1
 $1,379
 $1,401
 $(22) (2)

Interest expense increased $4 million for the third quarter of 2017 compared to 2016 and decreased $22 million for the first nine months of 2017 compared to 2016 due to repayments of BHE junior subordinated debentures of $944 million in 2017 and $2.0 billion in 2016, scheduled maturities and principal payments, early redemptions and the impact of foreign currency exchange rate movements of $8 million in the first nine months, partially offset by debt issuances at MidAmerican Funding, Northern Powergrid, AltaLink and BHE Renewables.



Capitalized Interest

Capitalized interest decreased $94 million for the first nine months of 2017 compared to 2016 primarily due to $96 million recorded in the second quarter of 2016 from the 2015-2016 GTAa regulatory decision received in May 2016November 2020 at AltaLink, which was offset in operating revenue, partially offset by higher construction work-in-progress balances at MidAmerican Energy.AltaLink.


Allowance for Equity Funds

Allowance for equity fundsEarnings increased $7 million for the third quarter of 20172021 compared to 2016 and decreased $882020, primarily due to higher earnings from the Montana-Alberta Tie-Line.

Operating revenue increased $31 million for the first nine months of 20172021 compared to 20162020, primarily due to $104$40 million recorded in the second quarter of 2016 from the 2015-2016 GTAstronger United States dollar and higher revenue from the Montana-Alberta Tie-Line of $10 million, partially offset by the impacts of regulatory decisions received in April and November 2020 at AltaLink.

Earnings increased $11 million for the first nine months of 2021 compared to 2020, primarily due to $11 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 May 2016April 2020 at AltaLink, which was offset in operatingAltaLink.

BHE Renewables

Operating revenue partially offset by higher construction work-in-progress balances at MidAmerican Energy.

Interest and Dividend Income

Interest and dividend income decreasedincreased $7 million for the third quarter of 20172021 compared to 20162020, primarily due to higher hydro, natural gas and solar revenues from higher generation and favorable market conditions, partially offset by an unfavorable change in the valuation of a power purchase agreement of $8 million and lower geothermal revenues from lower generation.

Earnings increased $1 million for the third quarter 2021 compared to 2020, primarily due to higher wind earnings of $6 million, mainly from tax equity investments offset by the unfavorable change in the valuation of a power purchase agreement, and higher hydro earnings of $5 million from higher generation, partially offset by lower geothermal earnings of $12 million, primarily due to lower geothermal generation and natural gas margin.

36

Operating revenue increased $42 million for the first nine months of 20172021 compared to 20162020, primarily due to lower dividends receivedhigher natural gas, hydro and solar revenues from BYD Company Limited.favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $22 million.


Other, net

Other, netEarnings decreased $13 million for the third quarter of 2017 compared to 2016 primarily due to costs associated with the early redemption of subsidiary long-term debt in 2017.

Other, net decreased $2$35 million for the first nine months of 20172021 compared to 2016 mainly2020, primarily due to costs associated withlower wind earnings of $56 million, largely from lower tax equity investment earnings of $48 million and the early redemptionunfavorable change in the valuation of subsidiary long-term debt in 2017 and an impairment of certain energy management assets at MidAmerican Energy Services, LLC,a power purchase agreement, partially offset by higher solar earnings of $18 million, mainly due to higher generation and lower depreciation expense, and higher hydro earnings of $5 million from higher generation. Tax equity investment returns and favorable changes inearnings decreased due to unfavorable results from existing tax equity investments of $123 million, primarily due to the valuationsFebruary 2021 polar vortex weather event, partially offset by $79 million of interest rate swap derivatives.earnings from projects reaching commercial operation.


Income Tax ExpenseHomeServices


Income tax expense decreased $15Operating revenue increased $1 million for the third quarter of 20172021 compared to 2016 and the effective tax rate was 15% for 2017 and 16% for 2016. The effective tax rate decreased2020, primarily due to higher production tax credits recognizedbrokerage revenue of $34 million and the favorable impacts of rate making of $10$117 million, partially offset by deferred income tax benefitslower mortgage revenue of $16$112 million reflectedfrom a 27% decrease in funded volume. The increase in brokerage revenue was due to $67 million from acquired companies and a 5% increase in closed transaction volume at existing companies, resulting from an increase in average sales price offset by fewer closed units.

Earnings decreased $75 million for the third quarter of 20162021 compared to 2020, primarily due to lower earnings from mortgage services of $76 million, largely attributable to the decrease in funded volume.

Operating revenue increased $910 million for the first nine months of 2021 compared to 2020, primarily due to higher brokerage revenue of $933 million from a 1% reduction34% increase in the United Kingdom corporate income tax rate.closed transaction volume, resulting from increases in closed units and average sales price, partially offset by lower mortgage revenue of $71 million from a decrease in refinance activity.


Income tax expense decreasedEarnings increased $75 million for the first nine months of 20172021 compared to 2016 and the effective tax rate was 13% for 2017 and 17% for 2016. The effective tax rate decreased2020, primarily due to higher production tax credits recognizedearnings from brokerage services of $96$84 million, andlargely due to the favorable impacts of rate making of $14 million,increase in closed transaction volume, partially offset by higher income tax expense on higher pre-tax income and deferred income tax benefitslower earnings from mortgage services of $16$28 million, reflected in the third quarter of 2016 due to a 1% reduction in the United Kingdom corporate income tax rate.

Production tax credits are recognized in earnings for interim periods based on the application of an estimated annual effective tax rate to pretax earnings. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a per-kilowatt rate pursuantlargely attributable to the applicable federal income tax lawdecrease in refinance activity offset by an unfavorable 2020 contingent earn-out remeasurement.

BHE and are eligible for the credit for 10 years from the date the qualifying generating facilities are placed in-service. Production tax credits recognized in 2017 were $432 million, or $96 million higher than 2016, while production tax credits earned in 2017 were $346 million, or $79 million higher than 2016. The difference between production tax credits recognized and earned of $86 million as of September 30, 2017, primarily at MidAmerican Energy, will be reflected in earnings over the remainder of 2017.Other


Equity Income

Equity incomeOperating revenue decreased $6$4 million for the third quarter of 20172021 compared to 20162020, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from lower volumes offset by favorable pricing.

Earnings decreased $1,118 million for the third quarter of 2021 compared to 2020, primarily due to the $1,046 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $86 million of lower federal income tax credits recognized on a consolidated basis, $26 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in October 2020 and $16unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower other corporate costs and higher earnings of $18 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts.

Operating revenue increased $82 million for the first nine months of 20172021 compared to 2016 due to lower pre-tax equity earnings from tax equity investments at BHE Renewables and lower equity earnings at Electric Transmission Texas, LLC,2020, primarily due to the impacts of new rates effective in March 2017.higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes.


Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests increased $5Earnings decreased $1,050 million for the first nine months of 20172021 compared to 20162020, primarily due to the $891 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $101 million of dividends on BHE's 4.00% Perpetual Preferred Stock, $44 million of lower federal income tax credits recognized on a consolidated basis, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by higher earnings of $30 million at HomeServices' franchise business.MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, and favorable changes in the cash surrender value of corporate-owned life insurance policies.




37

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 1718 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 20162020 for further discussion regarding the limitation of distributions from BHE's subsidiaries.


As of September 30, 2017,2021, the Company's total net liquidity was as follows (in millions):
MidAmericanNVNorthernBHE
BHEPacifiCorpFundingEnergyPowergridCanadaOtherTotal
Cash and cash equivalents$300 $893 $542 $99 $14 $72 $789 $2,709 
Credit facilities(1)
3,500 1,200 1,509 650 204 848 3,450 11,361 
Less:
Short-term debt— — — (127)(68)(230)(1,543)(1,968)
Tax-exempt bond support and letters of credit— (218)(370)— — (1)— (589)
Net credit facilities3,500 982 1,139 523 136 617 1,907 8,804 
Total net liquidity$3,800 $1,875 $1,681 $622 $150 $689 $2,696 $11,513 
Credit facilities:
Maturity dates202420242022, 2024202420232022, 20252022, 2026
     MidAmerican NV Northern      
 BHE PacifiCorp Funding Energy Powergrid AltaLink Other Total
                
Cash and cash equivalents$75
 $104
 $512
 $109
 $62
 $9
 $271
 $1,142
                
Credit facilities3,000
 1,000
 909
 650
 201
 1,062
 1,660
 8,482
Less:               
Short-term debt(1,405) —
 —
 —
 —
 (286) (802) (2,493)
Tax-exempt bond support and letters of credit(7) (130) (220) (80) —
 (7) —
 (444)
Net credit facilities1,588
 870
 689
 570
 201
 769
 858
 5,545
                
Total net liquidity$1,663
 $974
 $1,201
 $679
 $263
 $778
 $1,129
 $6,687
Credit facilities:               
Maturity dates2018, 2020
 2020
 2018, 2020
 2020
 2020
 2017, 2018, 2021
 2017, 2018, 2022
  


(1)    Includes drawn uncommitted credit facilities totaling $1 million at Northern Powergrid Holdings.

Operating Activities


Net cash flows from operating activities for the nine-month periods ended September 30, 20172021 and 20162020 were $5.1$7.0 billion and $4.8$4.5 billion, respectively. The changeincrease was primarily due to $886 million of incremental net cash flows from operating activities at BHE GT&S, improved operating results, changes in working capital and the payment for USA Power final judgment and post-judgment interest in the prior year, partially offset by a reduction infavorable income tax receipts and higher cash payments for interest.flows.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% in 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Production tax credits were extended and phased-out for wind power and other forms of non-solar renewable energy projects that begin construction before the end of 2019. Production tax credits are maintained at full value through 2016, at 80% of value in 2017, at 60% of value in 2018, and 40% of value in 2019. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, the Company's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019, production tax credits through 2029 and investment tax credits earned on qualifying wind and solar projects through 2021, respectively.


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 and assumptions used for each payment date.




Investing Activities


Net cash flows from investing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $(4.4)$(3.5) billion and $(4.1)$(6.6) billion, respectively. The change was primarily due to higher cash paid for acquisitions of $1.0 billion, partially offset by lower capital expenditures of $342 million and lower funding of tax equity investments.investments 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 a discussion of capital expenditures.


Financing Activities


Net cash flows from financing activities for the nine-month period ended September 30, 20172021 was $(330) million.$(2.0) billion. Uses of cash totaled $2.3$4.0 billion and consisted mainly of preferred stock redemptions totaling $1.5 billion, repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $366 million and junior subordinated debentures totaling $1.3 billion andnet repayments of subsidiaryshort-term debt totaling $834$316 million. Sources of cash totaled $1.9$2.0 billion and consisted of $1.6 billion of proceeds from subsidiary debt issuances and $365 million of net proceeds from short-term debt.issuances.

38

For a discussion of recent financing transactions, refer to Note 65 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.


Net cash flows from financing activities for the nine-month period ended September 30, 20162020 was $(792) million.$2.9 billion. Sources of cash totaled $5.9 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.6 billion. Uses of cash totaled $3.2$2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.6 billion, andnet repayments of short-term debt totaling $815 million, repayments of BHE junior subordinated debentures of $1.5 billion. Sources of cash totaled $2.4 billionsenior debt totaling $350 million and consisted of $1.5 billion of proceeds from subsidiary debt issuances and $887 million net proceeds from short-term debt.common stock repurchases totaling $126 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 Redemptions

On July 22, 2021, BHE redeemed at par 1,450,003 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $1.45 billion, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.

Common Stock Transactions

For the nine-month period ended September 30, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.

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; 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. Expenditures for certain assets may ultimately include acquisitions of existing assets.



39


The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Capital expenditures by business:
PacifiCorp$1,618 $1,157 $1,558 
MidAmerican Funding1,341 1,266 1,943 
NV Energy509 519 829 
Northern Powergrid492 564 748 
BHE Pipeline Group428 684 1,262 
BHE Transmission276 234 268 
BHE Renewables46 129 166 
HomeServices21 29 42 
BHE and Other(1)
(124)12 27 
Total$4,607 $4,594 $6,843 
 Nine-Month Periods Annual
 Ended September 30, Forecast
 2016 2017 2017
Capital expenditures by business:     
PacifiCorp$586
 $553
 $798
MidAmerican Funding1,129
 1,165
 2,006
NV Energy386
 333
 433
Northern Powergrid435
 434
 616
BHE Pipeline Group150
 174
 309
BHE Transmission386
 255
 343
BHE Renewables430
 239
 315
HomeServices13
 18
 34
BHE and Other6
 8
 13
Total$3,521
 $3,179
 $4,867
Capital expenditures by type:
Wind generation$1,388 $872 $1,122 
Electric distribution1,182 1,217 1,745 
Electric transmission745 539 845 
Natural gas transmission and storage385 647 1,097 
Solar generation2 104 218 
Other905 1,215 1,816 
Total$4,607 $4,594 $6,843 

(1)BHE and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Capital expenditures by type:     
Wind generation$1,110
 $804
 $1,292
Solar generation15
 95
 125
Electric transmission339
 267
 330
Environmental52
 56
 111
Other growth302
 400
 560
Operating1,703
 1,557
 2,449
Total$3,521
 $3,179
 $4,867


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 $275 million and $676 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $73 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $274 million and $25 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the repowering of wind-powered generating facilities totals $101 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service 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 892 MWs of current repowering projects not in-service as of September 30, 2021, 591 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.
40

◦Construction of wind-powered generating facilities at PacifiCorp totaling $99 million and $705 million for the nine-month periods ended September 30, 2021 and 2020, respectively. 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 the first nine months of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals $17 million for the remainder of 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $9 million and $99 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for the repowering of wind-powered generating facilities totals $7 million for the remainder of 2021.
◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $455 million and $732 million for the nine-month periods ended September 30, 2017 and 2016, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional $254 million for 2017. In August 2016, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 2,000 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2017 through 2019. The ratemaking principles establish 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. The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Additionally, the ratemaking principles modify the revenue sharing mechanism currently in effect. The revised sharing mechanism will be effective in 2018 and will be triggered each year by actual equity returns if they are above the weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. Each of these projects is expected to qualify for 100% of production tax credits currently available.
◦Repowering certain existing wind-powered generating facilities at PacifiCorp and MidAmerican Energy and the construction of new wind-powered generating facilities at PacifiCorp totaling $280 million for the nine-month period ended September 30, 2017. PacifiCorp and MidAmerican Energy anticipate costs for these activities will total an additional $221 million for 2017. The repowering projects entail the replacement of significant components of older turbines. The energy production from the repowered and the new facilities is expected to qualify for 100% of the federal renewable electricity production tax credits available for ten years once the equipment is placed in-service.


◦Construction of wind-powered generating facilities at BHE Renewables totaling $69 million and $378 million for the nine-month periods ended September 30, 2017 and 2016, respectively. BHE Renewables anticipates costs for wind-powered generating facilities will total an additional $11 million in 2017 and $263 million in 2018. BHE Renewables is developing and constructing up to 212 MW of wind-powered generating facilities in the state of Illinois.
Solar generation includes the construction of the community solar gardens project in Minnesota at BHE Renewables totaling $92$75 million for the nine-month period ended September 30, 2017.2021. In May 2021, BHE Renewables completed the asset acquisition of a 54 MW wind-powered generating facility located in Iowa. BHE Renewables anticipates costs for the community solar gardens projectto complete construction of this facility will total an additional $27$10 million in 20172021.
•Electric distribution includes both growth and $26 million in 2018.
Electric transmission includes PacifiCorp's costs associated with main grid reinforcement and the Energy Gateway Transmission Expansion Program, MidAmerican Energy's Multi-Value Projects approved by the Midcontinent Independent System Operator, Inc.operating expenditures. Growth expenditures include spending for the construction of approximately 250 miles of 345 kV transmission line located in Iowa and Illinois and AltaLink's directly assigned projects from the AESO.
Environmental includes the installation of new or the replacement of existing emissions control equipment at certain generating facilities at the Utilities, including installation or upgrade of selective catalytic reduction control systems and low nitrogen oxide burners to reduce nitrogen oxides, particulate matter control systems, sulfur dioxide emissions control systems and mercury emissions control systems, as well as expenditures for the management of coal combustion residuals.
Other growth includes projects to deliver power and services to new markets, new customer connections and enhancements to existing customer connections.
Operating includesexpenditures 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 PacifiCorp's 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. 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 liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
•Solar generation transmission, distributionincludes growth expenditures, including MidAmerican Energy's current plan for the construction of 141 MWs of small- and utility-scale solar generation during 2021, of which 61 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.
•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.

Acquisitions

The Company completed various acquisitions totaling $1.1 billion for the nine-month period ended September 30, 2017. The purchase price for each acquisition was allocateddemand, natural gas distribution, technology, and environmental spending relating to the assets acquired and liabilities assumed, which related primarily to residential real estate brokerage businesses, development and construction costs for the 110-megawatt Alamo 6 solar projectemissions control equipment and the 50-megawatt Pearl solar project, and the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power. As a resultmanagement of the acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $476 million and recognized goodwill of $522 million.coal combustion residuals.


Integrated Resource Plan

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In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP includes investments in renewable energy resources, upgrades to the existing wind fleet, and energy efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission, and new wind renewable resources will require an estimated $3 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million from the forecast included in BHE's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.


Other Renewable Investments


The Company has invested in 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 no contributions for the nine-month period ended September 30, 2021, and has commitments as of September 30, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $170 million in 2015, $584 million in 2016 and $85 million through September 30, 2017, and expects to contribute $317$766 million for the remainder of 20172021 and $254$414 million in 20182022 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.


Contractual Obligations


As of September 30, 2017,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 20162020 other than the recent financing transactions and the renewable tax equity investments previously discussed.




Quad Cities Generating Station Operating Status


Exelon Generation Company, LLC ("Exelon Generation"), 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 ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission creditsZECs will provide Exelon Generation 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 U.S. 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 in both suits and filed motions to dismiss in both matters. 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. The procedural schedule has been established for the appeals. MidAmerican Energy cannot predict the outcome of these lawsuits.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expandincludes a Minimum Offer Price Offer 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 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 in its order, 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 Exelon, 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 futurethat auction.

At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity auctionsmarket 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. A request for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms was filed on October 5, 2021, and remains pending.

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Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator ofconsiders Quad Cities Station Exelon Generation has filed proteststo be at heightened risk for early retirement. However, to the FERC in response to each filing.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 timingFERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the FERC’s decision with respectIllinois zero emission standard unless the PJM adopts further changes to both proceedings is currently unknown and the outcome of these matters is currently uncertain.MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.


Regulatory Matters


BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016,2020 and new regulatory matters occurring in 2017.2021.


PacifiCorp

In June 2017, PacifiCorp filed two applications each with the UPSC, IPUC and the WPSC for the Energy Vision 2020 project. The first application seeks approvals to construct or procure four new Wyoming wind resources with a total capacity of 860 MWs identified as benchmark resources and certain transmission facilities. A request for proposals was issued in September 2017 seeking up to 1,270 MWs to compete against PacifiCorp's benchmark resources in the final resource selection process for the project. PacifiCorp estimates the combined wind and transmission projects will cost approximately $2 billion. The WPSC, UPSC, and IPUC have set procedural schedules with hearings to occur in the first quarter of 2018. The second application seeks approval of PacifiCorp's resource decision to upgrade or "repower" existing wind resources, as prudent and in the public interest. PacifiCorp estimates the wind repowering project will cost approximately $1 billion. The hearings on repowering in Utah, Idaho and Wyoming will occur in November 2017, December 2017, and January 2018, respectively. Applications filed in Utah, Idaho and Wyoming seek approval for the proposed ratemaking treatment associated with the projects.


Utah


In March 2017,2020, PacifiCorp filed its annual Energy Balancing Account ("EBA")application with the UPSC seeking approval to refund to customers $7requesting recovery of $37 million inof deferred net power costs from customers for the period January 1, 20162019 through December 31, 2016,2019, reflecting the difference between base and actual net power costs in the 20162019 deferral period. In April 2017, PacifiCorp revised its recommendation and requested approvalThis reflected a 1.0% increase compared to refund an additional $7 million to customers resultingcurrent rates. The UPSC approved the request in an interim rate reduction of $14 million. The rate change becameFebruary 2021 for rates effective on an interim basis MayMarch 1, 2017.2021.




In March 2017,2021, PacifiCorp filed its annual REC balancing accountEnergy Balancing Account application with the UPSC seeking to refund torequesting recovery of $2 million of deferred net power costs from customers $1 million for the period January 1, 20162020 through December 31, 2016 for2020, reflecting the difference inbetween base and actual RECs.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 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 change becamecase. 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 Energy Balancing Account. A hearing has been scheduled beginning November 2021.

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. The application also requests approval of a surcharge to collect $5 million per year for 10 years. The proposed surcharge would replace the existing Sustainable Transportation and Energy Plan cost adjustment that will expire on December 31, 2021. PacifiCorp's request would result 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.

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In July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an interim basis Juneapplication 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, 2017.2022, to recover the incremental costs from those approved in the last general rate case.


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 Utah Sustainable Transportation and Energy Plan legislation that was signed into law in March 2016,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 2016 seeking approval of a proposed five-year pilot program with an annual budget of $10 million authorized under2021, the legislation to address clean-coal technology programs, commercial line extension programs, an electric vehicle incentive program and associated residential time of use rate pilot and other programs authorized in legislation. The UPSC issued orders approvingWPSC approved 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. The WPSC will address recovery of the deferred costs in phases in December 2016, May 2017 and June 2017.a future general rate case.


In November 2016, PacifiCorp filed cost of service analyses, as ordered by the UPSC, to quantify the cost shifting due to net metering. The UPSC ordered the analyses to comply with a 2014 law requiring the examination of whether the costs of net metering exceed the benefits to PacifiCorp and other customers. The filing includes a proposal for a new rate schedule for residential customer generators with a three-part rate based on the cost of serving this class of customer, which will mitigate future cost shifting. PacifiCorp proposed that the new rate schedule only apply to new net metering customers that submit applications after December 9, 2016. On December 9, 2016, PacifiCorp requested that the effective date for the start of a transitional tariff be suspended while it works with stakeholders on a collaborative process to resolve net metering rate design issues. The filing also requests an increase in the application fees for net metering. In February 2017, the UPSC ruled on motions to dismiss and requests for a show cause order for a regulatory rate review filed by various parties to the docket and denied the motions. On August 28, 2017,March 2020, PacifiCorp filed a settlement stipulationgeneral 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 net metering proceeding.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 the 2017 Tax Reform benefits. The stipulation providesWPSC 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 closurehearings. 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 results in an overall net metering program to new entrants on November 15, 2017,decrease of 3.5% with a transition to a new program that provides a separate compensation rate for exported power.All net metering customers, including those with a submitted application, aseffective date of November 15, 2017, will be grandfathered into the current program until JanuaryJuly 1, 2036.2021. A new proceeding will be initiated to establish a methodology for the determination of the export credit for new customers. During this period, a transition program for new customers will commence November 15, 2017, for a limited number of customers. Beginning December 1, 2017, PacifiCorp will start accepting applications for the new transition program for private generation customers. Residential and non-residential private generation customers will be compensated for exported energy at 90% and 92.5% of the current average energy rates, respectively. The rates for the exported energy will be fixed through January 1, 2033 for these transition program customers. The new residential and non-residential transition program customers’ compensation will be only available for the first 170 MW and 70 MW, respectively. The stipulation also includes an agreement to support a two-year extension on the state tax credit for residential solar installations. A hearing on the stipulation was held on September 18, 2017, and anfinal written order approving it was issued September 29, 2017.

Oregon

In March 2017, PacifiCorp submitted its filing for the annual Transitional Adjustment Mechanism ("TAM") filing in Oregon requesting an annual increase of $18 million, or an average price increase of 1.5%, based on forecasted net power costs and loads for calendar year 2018. Consistent with Oregon Senate Bill 1547, the filing includes an update of the impact of expiring production tax credits, which accounts for $6 million of the total rate adjustment. The filing was updated in July to reflect changes in contracts and market conditions. The updated filing is requesting an annual increase of $8 million, or an average price increase of 0.6%. The filing will be updated for changes in contracts and market conditions again in November 2017, before final rates become effective in January 2018.2021.

Wyoming


In April 2017,2021, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM")ECAM and REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applicationsapplication with the WPSC. The ECAM filing requests approvalWPSC requesting to refund to customers $5$15 million inof deferred net power costs and RECs to customers for the period January 1, 20162020 through December 31, 2016,2020, reflecting the difference between base and actual net power costs in the RRA application requests approval2020 deferral period. This reflects a 2.4% decrease compared to refund to customers $1 million. In June 2017, the WPSC approved the ECAM and RRA rates oncurrent rates. PacifiCorp requested an interim basis until a final order is issuedrate effective July 1, 2021, which was approved by the WPSC which is expected in June 2021. PacifiCorp filed an all-party stipulation in October 2021. A hearing on the first quarter of 2018.stipulation was held in November 2021.

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Washington


In August 2017,June 2021, PacifiCorp submittedfiled a compliance filingpower cost only rate case to implement the second-yearupdate baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase approvedhas 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 two-year rate plancompliance filing. A hearing in the 2015 regulatory rate review. The compliance filing included rates based on the $8 million, or 2.3%, increase ordered by the WUTC in September 2016. The compliance filing was approved by the WUTC on September 14, 2017,this matter is scheduled for January 2022 with rates becoming effective September 15, 2017.after an order is issued.




Idaho

In January 2017, a $1 million, or 0.4%, decrease in base rates became effective as a result of a filing made with the IPUC to update net power costs in base rates in compliance with a prior rate plan stipulation.


In March 2017,2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $8$14 million for deferred costs in 2016.2020, 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, 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 Deer Creek longwall mine investment and changes in production tax credits and renewable energy credits. The IPUC approved the ECAM application with$10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2017.2021.


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%. A hearing on the settlement has been scheduled for November 2021 for rates to be effective January 1, 2022.

California


California Senate Bill 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 April 2017,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 overall rate increase of 1.3%$1 million, or 0.8%, to recover $3 million of costs recorded in the catastrophic events memorandum account over a two-year period effective April 1, 2018. The catastrophic events memorandum account includes costs for implementing drought-related fire hazard mitigation measurespurchasing 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 storm damage and recovery efforts associated with the December 2016 and January 2017 winter storms.in November 2021, approved updated rates for energy costs as filed.


In August 2017,2021, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes 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 $1$2 million, or 1.1%1.9%, through its annual Energy Cost Adjustment Clause. If approvedeffective January 1, 2022. As of November 2021, the CPUC has not set a procedural schedule for this application.

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 North American Electric Reliability Corporation (the "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 CPUC,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 ratesFERC'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.
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MidAmerican Energy

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 nine-month period ended September 30, 2021.

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 MidAmerican Energy wind-powered generation additions and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the program, 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 project would be effective January 2018.specifically assigned to subscribing customers. In June 2021, the IUB rejected the proposed RSP tariff. In a separate docket, the IUB ordered the exclusion from MidAmerican Energy's energy adjustment clause all PTCs and energy benefits associated with projects addressed in the RSP, resulting in MidAmerican Energy retaining such benefits.

NV Energy (Nevada Power and Sierra Pacific)


Regulatory Rate ReviewsPrice Stability Tariff


In June 2017,November 2018, the Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $29 million, or 2%, but requested no incremental annual revenue relief. The hearings are scheduled in the last quarter of 2017. The PUCN is expected to complete the hearings by the end of 2017, but the PUCN has not indicated when they will issue a final order or when that order would become effective.

In June 2016, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. In October 2016, Sierra Pacific filedUtilities made filings with the PUCN a settlement agreement resolving most, but not all, issues into implement the proceeding and reduced Sierra Pacific's electric revenue requirement by $3 million spread evenlyCPST. The Nevada Utilities have designed the CPST to all rate classes. In December 2016, the PUCN approved the settlement agreement and establishedprovide certain customers, namely those eligible to file an additional six MW of net metering capacity under the grandfathered rates, which are those net metering rates that were in effect priorapplication pursuant to January 2016; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. The new rates were effective January 1, 2017. In January 2017, Sierra Pacific filed a petition for reconsideration relating to the creation of the additional six MWs of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision result in additional cost shifting to non-net metering customers and reduces the stipulated rate reduction for other customer classes. In June 2017, the PUCN denied the petition for reconsideration.

In June 2016, Sierra Pacific filed a gas regulatory rate review with the PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving all issues in the proceeding and reduced Sierra Pacific's gas revenue requirement by $2 million. In December 2016, the PUCN approved the settlement agreement. The new rates were effective January 1, 2017.

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes, allows retail electric customers with a market-based pricing option that is based on renewable resources. The CPST provides for an average annual load of one MW or moreenergy rate that would replace the Base Tariff Energy Rate and Deferred Energy Accounting Adjustment. The goal is to filehave an energy rate that yields an all-in effective rate that is competitive with the PUCN an applicationmarket options available to purchase energy from alternative providers of a new electric resource and become distribution only servicesuch 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 May 2015, MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed applications with the PUCN to purchase energy from alternative providers of a new electric resource and become distribution only service customers of Nevada Power. In December 2015,February 2019, the PUCN granted several intervenors the applications subjectability to conditions, including payingparticipate 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 impact fee, on-going chargesorder approving the tariff with modified pricing and receiving approvaldirecting 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 specific alternative energy providers and terms.potentially interested customers as filed. In December 2015,2020, the applicantsNevada 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. A final order has not been issued but because no customers have enrolled the order may be dismissed or withdrawn and the tariff will not go into effect. A final order is expected in 2021.

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Natural Disaster Protection Plan

The Nevada Utilities submitted their initial natural disaster protection plan 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 minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a petition for judicial review with the District Court in November 2020. In January 2016,December 2020, the PUCN granted reconsiderationissued a second modified final order approving the natural disaster protection plan, as modified, and updated some ofreopened its investigation and rulemaking on Senate Bill 329 to address rate design issues raised by intervenors. The comment period for the terms, including removing a limitation related to energy purchased indirectly from NV Energy.reopened investigation and rulemaking ended in early February 2021 and an order is expected in 2021. In September 2016, MGM and Wynn paid impact fees of $82 million and $15 million, respectively. In October 2016, MGM and Wynn became distribution only service customers 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 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 May 2017, a stipulation reached between MGM, Regulatory Operations Staff and the Bureau of Consumer Protection was filed requiring Nevada Power to credit $16 million as an offset against MGM's remaining impact fee obligation and, in June 2017, the PUCN approved the stipulation as filed.

In September 2016, Switch, Ltd. ("Switch"), a customer ofMarch 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial natural disaster protection plan that was ordered by the PUCN and filed their first amendment to the 2020 natural disaster protection plan. A hearing related to the application for approval of the first amendment to the 2020 natural disaster protection plan 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 for cost recovery. In July 2021, a hearing was held regarding the recovery of the 2020 costs held in a regulatory asset account and the cost recovery mechanism. In September 2021, the PUCN issued an order, approving the recovery of the 2020 costs with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management costs were to purchase energybe removed from alternative providersthe 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 new electric resourcestatewide rate for operating costs and become a distribution only service customerterritory specific rate 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. The PUCN will reexamine the record and issue a modified order or reaffirm its original order with the outcome expected in the fourth quarter of 2021.

Senate Bill 448 ("SB 448")

SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage within the state of Nevada Power and Sierra Pacific.requires the Nevada Utilities to submit a plan to accelerate transportation electrification in the state and file a plan for certain high-voltage transmission infrastructure projects. SB 448 requires the Nevada Utilities to amend its most recently filed resource plan to include a plan for certain high-voltage transmission infrastructure construction projects that will be placed into service not later than December 31, 2028 and requires the IRP to include at least one scenario of low carbon dioxide emissions that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. SB 448 also requires the Nevada Utilities, on or before September 1, 2021, to file a plan to invest in certain transportation electrification programs during the period beginning January 1, 2022, and ending on December 31, 2024, and establishes requirements for the contents of the transportation electrification investment plan for that period. It also establishes requirements for the review and the acceptance or modification of the transportation electrification investment plan by the PUCN. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions, including paying an impact fee to Nevada Power. In May 2017, Switch paid impact fees of $27 million and, in June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

In November 2016, Caesars Enterprise Service ("Caesars"), a customer ofSeptember 2021, the Nevada Utilities filed an application withfor the PUCNapproval of their Economic Recovery Transportation Electrification Plan to purchase energy from alternative providersaccelerate transportation electrification in the state of a new electric resource and become a distribution only service customer of Nevada Power and Sierra Pacific.Nevada. 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 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 ofaddition, the Nevada Utilities.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 certain high-voltage transmission infrastructure. The PUCN opened rulemakings to address the regulations in SB 448.


ON Line Temporary Rider ("ONTR")

In May 2017, Peppermill Resort Spa Casino ("Peppermill"), a customer ofOctober 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR and corresponding updates to purchase energy from alternative providersits electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a new electric resource and become a distribution only service customerresult 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.

Net Metering

Nevada enacted Senate Bill 374 ("SB 374") on June 5, 2015. The legislation required the Nevada Utilities to prepare cost-of-service studies and propose new rules and rates for customers who install distributed, renewable generating resources. In July 2015, the Nevada Utilities made filings in compliance with SB 374ON Line cost reallocation and the PUCN issued final orders December 23, 2015.

The final orders issuedon-going reallocated revenue requirement. Sierra Pacific's application would, if approved by the PUCN establish separateas filed, result in a one-time rate classesincrease of $28 million to be collected over a nine-month period starting on April 1, 2022.

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Northern Powergrid Distribution Companies

In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution networks in Great Britain. Regarding the allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). In March 2021, all the transmission and gas distribution networks lodged appeals with the Competition and Markets Authority against Ofgem's determination for the cost of equity. In August 2021, the Competition and Markets Authority published a provisional determination that proposed to uphold the 4.55% cost of equity, which was confirmed in their final determination in October 2021. These determinations do not apply directly to Northern Powergrid, but aspects of the proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023.

In December 2020, GEMA published its decision on the methodology it will use to set the next electricity distribution price control, ED2, and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution, and that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a working assumption for a cost of equity at 4.65% (plus CPIH), ahead of the final determinations in late 2022. When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, the working assumption for ED2 is approximately 150 basis points lower than the current cost of equity.

In July 2021, Northern Powergrid submitted and published its draft business plan for April 2023 to March 2028. If adopted, this plan would involve annual capital and operating expenditures of £642 million, an increase relative to the £471 million average annual capital and operating expenditures expected over the current price control period (April 2015 to March 2023). A final business plan submission for 2023-2028 will be submitted in December 2021, ahead of GEMA's draft and final determinations which are expected around June and December 2022, respectively. A new price control can be implemented by GEMA without the consent of the licensee but, if a licensee disagrees with the decision, it can appeal the matter to the United Kingdom's Competition and Markets Authority. In general terms, an appeal may also be sought by another licensee whose interests are materially affected by the decision, a trade association that represents a licensee and Citizens Advice, as the representative of consumers whose interests are materially affected by the decision.

BHE Pipeline Group

BHE GT&S

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 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, 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 $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.

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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.

In April 2021, the AUC confirmed its approval of AltaLink's customer tariff refund as provided in the decision issued in March 2021 and detailed its reasons for the decision. Specifically, the AUC found that the exceptional circumstances faced by Alberta customers in 2021 brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances included the current economic downturn due to COVID-19, the collapse in the world price of oil and the resulting significant negative impact to Albertans and businesses. As a result, immediate and temporary relief was warranted.

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 who install distributed, renewable generating facilities.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 establishmentapplication requested the approval of separate rate classes recognizesrevised 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 unique characteristics, costs and services received by these partial requirements customers.AUC. The PUCN also established new, cost-based rates or prices for these new customer classes, including increasesapplication consisted of negotiated reductions that resulted in the basic service charge and related reductions in energy charges. Finally, the PUCN established a separate value for compensating customers who produce and deliver excess energynet decrease of C$38 million to the Nevada Utilities.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 valuation will consider eleven factors, including alternatives available to the Nevada Utilities. The PUCN established a gradual, five-step process for transition over four years2019-2021 negotiated settlement agreement excluded certain matters related to the new cost-based rates.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. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020.




In January 2016, the PUCN denied requests to stay the order issued December 23, 2015. The PUCN also voted to reopen the evidentiary proceeding to address the application of new net metering rules for customers who applied for net metering service before the issuance of the final order. In February 2016, the PUCN affirmed most of the provisions of the December 23, 2015 order and adopted a twelve-year transition plan for changing rates for net metering customers to cost-based rates for utility services and value-based pricing for excess energy. Subsequently, two solar industry interest groups filed petitions for judicial review of the PUCN order issued in February 2016. The petitions request that the court either modify the PUCN order or direct the PUCN to modify its decision in a manner that would maintain rates and rules of service applicable to net metering as existed prior to the December 23, 2015 order of the PUCN. Two of the three petitions filed by the solar industry interest groups have been dismissed. In September 2016, the state district court issued an order in the third petition. The court concluded that the PUCN failed to provide existing net metering customers adequate legal notice of the proceeding. The court affirmed the PUCN's decision to establish new net energy metering rates and apply those to new net metering customers. The Nevada state district court decision was appealed to the Nevada Supreme Court.

In July 2016, the Nevada Utilities filed applications with the PUCN to revert back to the original net metering rates for a period of twenty years for customers who installed or had an active application for distributed, renewable generating facilities as of December 31, 2015. In September 2016, the PUCN issued an order accepting the stipulation and approved the applications as modified by the stipulation. In December 2016, as a part of Sierra Pacific's regulatory rate review, the PUCN issued an order establishing an additional six MWs of net metering under the grandfathered rates in the Sierra Pacific service territory; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. As mentioned above, Sierra Pacific filed a petition for reconsideration relating to the additional six MWs of net metering, which was denied in June 2017.

In March 2017, the Nevada Utilities filed a joint application with several solar companies to extend the period for eligible customers to opt into the grandfathered net metering rates. The PUCN voted to approve the application and gave qualifying customers until July 2017 to make this election.

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the next 80 MWs of cumulative installed capacity in Nevada, 81% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the next 80 MWs of cumulative installed capacity in Nevada and 75% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for any additional private generation capacity. In July 2017, the Nevada Utilities filed with the PUCN proposed amendments to their tariffs necessary to comply with the provisions of AB 405. The filing in July 2017 also included a proposed optional time of use rate tariff for both Nevada Power and Sierra Pacific, which has not yet been set for procedural review. In September 2017, the PUCN issued an order directing the Nevada Utilities to place all new private generation customers who have submitted applications after June 15, 2017, into a new rate class with rates equal to the rate class they would be in if they were not private generation customers. Private generation customers with installed net metering systems less than 25 kilowatts prior to June 15, 2017, may elect to migrate to the new rate class created under AB 405 or stay in their otherwise-applicable rate class.

Energy Choice Initiative

In November 2016, a majority of Nevada voters supported a ballot measure to amend Article 1 of the Nevada Constitution. If approved again in the general election of 2018, the proposed constitutional amendment would require the Nevada Legislature to create, on or before July 2023, an open and competitive retail electric market that includes provisions to reduce costs to customers, protect against service disconnections and unfair practices and prohibit the granting of monopolies and exclusive franchises for the generation of electricity. The outcome of any customer choice initiative could have broad implications to the Nevada Utilities. The Governor issued an executive order establishing the Governor’s Committee on Energy Choice in which the Nevada Utilities have representation. The Nevada Utilities are engaged in the initiative process and with the Governor's Committee on Energy Choice but cannot assess or predict the outcome of the potential constitutional amendment or the financial impact, if any, at this time. The uncertainty created by the ballot initiative complicates both the short-term allocation of resources and long-term resource planning for the Nevada Utilities, including the ability to forecast load growth and the timing of resource additions. This uncertainty in planning is evidenced by a recent decision the PUCN issued denying Nevada Power’s proposed purchase of the South Point Energy Center, citing the unknown outcomes of the energy choice initiative as one of the factors considered in their decision.



ALP

General Tariff Applications

In November 2014, ALP filed a GTA requesting the AUC 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 AESO. ALP amended the GTA in June 2015 and in October 2015. 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 and to provide customers with tariff relief through: (i) the discontinuance of construction work-in-progress ("CWIP") in rate base and the return to AFUDC accounting effective January 1, 2015, and (ii) the refund of previously collected CWIP in rate base as part of ALP's transmission tariffs during 2011-2014 less related returns. In October 2016, ALP amended its 2015-2016 GTA compliance filing made in July 2016 to reflect the impacts of the generic cost of capital decision issued in October 2016.

In December 2016,April 2020, the AUC issued its decision with respect to ALP’s 2015-2016 GTAAltaLink'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 madeestablishing 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.

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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 2016, as amended. The AUC found that ALP has either complied with or the AUC has otherwise relieved ALP from its compliance with all its directions in its decision except for Directive 47, which dealt with the determination of the refund for previously collected CWIP-in-rate base and all related amounts. In January 2017, ALP2020, AltaLink filed its second compliance filing as directed by the AUC and requested a technical conference to explain the technical aspects of the filing.

In March 2017, the technical conference was held, and all key aspects of ALP’s approach and methodologies used in its second compliance filing to comply with AUC directives were reviewed and discussed. In April 2017, ALP filedan application with the AUC an amendmentfor the review and variance of the AUC's decision with respect to its second compliance filing askingAltaLink'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 remove C$7 million of recapitalized AFUDC associated with canceled projects that were not capitalized to rate base, and to increasematerially vary or rescind the amount of income tax refund related to previously collected CWIP-in-rate base by C$4 million. As a result of this amendment, ALP’s forecast transmission tariffs were reduced from C$679 million to C$675 million for 2016, and remained unchanged at C$599 million for 2015, compared to the January 2017 second compliance filing, as amended.

During the second quarter 2017, ALP respondedmajority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, with respect to its second compliance filing amendmentwritten argument was filed in April 2017.by intervening parties and written reply argument was filed by AltaLink. In August 2017,November 2020, the AUC issued aits decision with respect to ALP's second compliance filing amendment filed in April 2017.on AltaLink's review and variance application. The AUC denied ALP's proposaldecided to remove C$7 million of recapitalized AFUDC associated with canceled projects onvary the basis thatoriginal decision and approve AltaLink's proposed net salvage method and the amount would more appropriately be recovered through ALP's deferral account reconciliation process. In addition, the AUC reaffirmed ALP's 2016 refund of C$267 million of previously collected CWIP-in-rate base, along with C$45 million of cumulative return thereon.revised transmission tariffs as filed, effective December 2020. The AUC also directed the recalculation ofnew salvage methodology decreased the amount of related income taxes using typical direct assigned project schedulessalvage 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 inits 2022-2023 GTA delivering on the general tariff applications,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 to adjust its funded futurecontinuing the use of the flow-through income tax liability onlymethod, 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 change in timing differences.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 2017, ALP filed with2021, AltaLink provided responses to information requests from the AUC its third compliance filing, which proposesand 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. Oral argument and reply argument were completed in a one-time payment to the AESO of C$7 million to settle the 2015-2016 final transmission tariffs. Further direction or a finalhearing in October 2021. A decision from the AUC is expected in the fourth quarter 2017. Once the AUC approves ALP’s third compliance filing, final transmission tariff rates for the 2015 and 2016 test years will be set, subject to further adjustment through the deferral account reconciliation process.January 2022.


ALP updated and refiled its 2017-2018 GTA in August 2016 to reflect the findings and conclusions of the AUC in its 2015-2016 GTA decision issued in May 2016. In October 2016, ALP amended its 2017-2018 GTA to reflect the impacts of the generic cost of capital decision issued in October 2016 and other updates and revisions. The amendment requests the AUC to approve ALP's revenue requirement of C$891 million for 2017 and C$919 million for 2018. In November 2016, the AUC approved the 2017 interim refundable transmission tariff at C$70 million per month effective January 2017. In December 2016, the AUC approved ALP's request to enter into a negotiated settlement process. In January 2017, the parties successfully reached a negotiated settlement on all aspects of ALP’s 2017-2018 GTA and in February 2017, ALP filed with the AUC the 2017-2018 negotiated settlement application for approval. The application consists of negotiated reductions of C$16 million of operating expenses and C$40 million of transmission maintenance and information technology capital expenditures over the two years, as well as an increase to miscellaneous revenue of C$3 million. These reductions resulted in a C$24 million, or 1.3%, net decrease to the two-year total revenue requirement applied for in ALP’s 2017-2018 GTA amendment filed in October 2016. In addition, ALP proposed to provide significant tariff relief through the refund of previously collected accumulated depreciation surplus of C$130 million (C$125 million net of other related impacts). The negotiated settlement agreement also provides for additional potential reductions over the two years through a 50/50 cost savings sharing mechanism.



During the second quarter 2017, ALP responded to information requests from the AUC with respect to its 2017-2018 negotiated settlement agreement application filed in February 2017. In August 2017, the AUC issued a decision approving ALP's negotiated settlement agreement for the 2017-2018 GTA, as filed. Also, the AUC approved a C$31 million refund of accumulated depreciation surplus as opposed to the C$130 million refund proposed in the original application. In November 2017, ALP filed a compliance filing with the AUC to reflect the reduction of the accumulated depreciation surplus refund and related adjustments.

20182022 Generic Cost of Capital Proceeding


In July 2017,December 2020, the AUC deniedinitiated the utilities’ request that2022 generic cost of capital proceeding. This proceeding considered the interim determinations of 8.5% return on equity and deemed capital structuresequity ratios for 20182022 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 commission 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 made final, byutilized; (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 it is not prepareddue to finalize 2018 values inongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the absence of an evidentiary processcurrently approved 2021 return on equity and its intentiondeemed equity ratio on a final basis for 2022. AltaLink further stated there was insufficient time to issue thecomplete 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 2018, 20192023 and 2020 bysubsequent years.

In March 2021, the end of 2018AUC issued its decision with respect to reduce regulatory lag.setting the return on equity and deemed equity ratios for AltaLink. The AUC also confirmedapproved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the process timelines with an oral hearing scheduledunsettled nature of capital markets, and the need for March 2018.certainty and stability for Alberta customers.


Deferral Account Reconciliation Application
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In April 2017, ALP2021, the Utilities Consumer Advocate filed an application with the Alberta Court of Appeal requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and equity ratio of 37% on a final basis for 2022. In the appeal, the Utilities Consumer Advocate alleged that the AUC erred by failing to fulfill its statutory obligation of establishing a fair return and by failing to apply procedural fairness. The Utilities Consumer Advocate additionally filed an application with the AUC for review and variance of the AUC's decision. The basis for the application was the same as the permission to appeal filed with the Alberta Court of Appeal.

In August 2021, the AUC denied the Utilities Consumer Advocate's application for review and variance of its decision that extended the approved 2020 and 2021 return on equity of 8.5% and equity ratio of 37% to 2022. In September 2021, the Alberta Court of Appeal heard the Utilities Consumer Advocate's permission to appeal application. In October 2021, the Alberta Court of Appeal issued its judgement dismissing the Utilities Consumer Advocate's application for leave to appeal the AUC decision setting final rates for 2022.

2019 Deferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes 10 projects with respecttotal gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to ALP’s 2014 projectsAUC information requests, interveners filed written argument and AltaLink filed reply argument.

In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128 million of the C$128.5 million of gross capital project additions, disallowing C$0.5 million of capital costs. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and specific 2015 projects. The application includes approximately C$2.0 billionannual structure payments as filed. AltaLink filed its compliance filing in net capital additions.April 2021. In June 2017,May 2021, the AUC ruled thatissued its decision approving the scope of the deferral account proceeding would not be extended to consider the utilization of assets for which final cost approval is sought. However, the AUC will initiate a separate proceeding to address the issue of transmission asset utilization and how the corporate and property law principles applied in the Utility Asset Disposition ("UAD") decision may relate.compliance filing application as filed.


In June 2017, the AUC also suspended the process in order to address a conflict of interest issue related to the provision of confidential documents.

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, 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 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 the EPA and 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. Refer to "Liquidity and Capital Resources" of each respective Registrant in Part I, Item 2 of this Form 10-Q for discussion of each Registrant's forecast environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016,2020, and new environmental matters occurring in 2017.2021.


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 goals 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 greenhouse gas 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 April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.
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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:
•On July 27, 2021, the governor of Oregon 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. No earlier than January 1, 2022, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets.
•On May 17, 2021, the state of Washington passed the Climate Commitment Act (Senate Bill 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.

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.


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 best available retrofit technology ("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 sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Certain groups appealed the EPA's approval of the sulfur dioxide portion and oral argument was heard before the United States Court of Appeals for the Tenth Circuit ("Tenth Circuit") in March 2014. In October 2014, the Tenth Circuit upheld the EPA's approval of the sulfur dioxide portion of the SIP. The state of Utah and PacifiCorp filed petitions for administrative and judicial review of the EPA's final rule on the BART determinations for the nitrogen oxides and particulate matter portions of Utah's regional haze SIP in March 2013. In May 2014, the Tenth Circuit dismissed the petition on jurisdictional grounds. In addition, and separate from the EPA's approval process and related litigation, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. The alternative BART analysis and revised regional haze SIP were submitted in June 2015 to the EPA for review and proposed action after a public comment period. The revised regional haze SIP included a state-enforceable requirement to cease operation of the Carbon Facility by August 15, 2015. PacifiCorp retired the Carbon Facility in December 2015. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to nitrogen oxides controls and require the installation of selective catalytic reduction ("SCR") controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. 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 controls 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 have filed requests with the EPA to reconsider and stay that decision, and have also filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA’s actions. In June 2017, the state of Utah and PacifiCorp issued requests to the EPA to reconsider its decision in issuing the FIP. By letter dated July 14, 2017, from Administrator Scott Pruitt, the EPA indicated that based on existing and new evidence potentially relevant to the EPA’s evaluation of Utah’s 2015 SIP, the agency would reconsider its final rule and prepare a notice of proposed rulemaking and take public comment on its proposed action. On July 18, 2017, the EPA filed with the Tenth Circuit a motion to hold the pending appeals in abeyance pending agency reconsideration of the final rule. The Tenth Circuit initially requested that all parties file a response setting forth their opposition or nonopposition to the EPA’s motion to hold the cases in abeyance by July 28, 2017. However, on July 18, 2017, PacifiCorp asked the Tenth Circuit to take judicial notice of the EPA’s request to hold the appeals in abeyance and reaffirmed its request to stay the FIP. The Tenth Circuit ordered all parties to respond to both the EPA's motion for abeyance and the motions by PacifiCorp and others to take judicial notice of EPA's reconsideration by August 4, 2017. On September 11, 2017, the Tenth Circuit issued an order granting both the motion to hold the case in abeyance and the motions for stay. The stay tolls the compliance requirements of the federal implementation plan for the number of days the stay is in effect while the EPA reconsiders the basis for the issuance of the federal plan.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions requiring SCR controls on Cholla Unit 4. In January 2015, permit applications and studies were submitted to amend the Cholla Title V permit, and subsequently the Arizona SIP to convert Cholla Unit 4 to a natural gas-fueled unit in 2025; after notice and comment, the Arizona Department of Environmental Quality submitted the amended Arizona SIP to the EPA, which approved the amendments to the Arizona regional haze SIP with an effective date of April 26, 2017.

The Navajo Generating Station, in which Nevada Power is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. Nevada Power, along with the other owners of the facility, have been reviewing the EPA's proposal to determine its impact on the viability of the facility's future operations. The land lease for the Navajo Generating Station is subject to renewal in 2019. In the spring 2017, the owners of the Navajo Generating Station voted to shut down and demolish the plant on or before December 23, 2019; however, the owners agreed to continue operating the plant through 2019 with demolition to follow if the tribe approved a new lease by July 1, 2017. Subsequently, the Navajo Council approved the requested lease extension June 26, 2017, and on July 1, 2017, the Navajo Nation signed the replacement lease with the utility owners of the Navajo Generating Station. Two remaining owners, the U.S. Bureau of Reclamation and the City of Los Angeles, must approve the lease by December 1, 2017, to enable continued operations through 2019. The Navajo Nation, along with the U.S. Bureau of Reclamation and Peabody Energy have further indicated a desire to keep the plant and coal mine operating through at least 2030, which would require a new ownership structure for the facility. The utility owners have specified that a new ownership proposal must be put forward by October 1, 2017, in order to complete the transition prior to December 23, 2019. Nevada Power filed the Emissions Reduction and Capacity Replacement Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. Bids to sell the facility were due to Salt River Project on October 1, 2017; however, none were tendered by that date. The owners were subsequently informed that several interested parties are preparing bids which are expected for submittal and review in late October. Any potential new owner, along with the Navajo Nation has until November 1, 2017, to reach an agreement in principle and one year from that date to reach a new ownership agreement and lease. In light of the tight time frames involved, it is expected that any bid received at this time will be highly conditioned.



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; 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 greenhouse gas emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global greenhouse gas emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. Under the terms of the Paris Agreement, ratifying countries are bound for a three-year period and must provide one-year's notice of their intent to withdraw. The Clean Power Plan, which was finalized by the EPA in 2015 and is currently under review, was the primary basis for the United States' commitment under the Paris Agreement. On June 1, 2017, President Trump announced the United States would begin the four-year process of withdrawing from the Paris Agreement.

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-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards have beenwere appealed to the D.C. Circuit and oral argument was scheduled to be heardfor April 17, 2017; however,2017. However, oral argument was deferred and the court canceled the oral arguments March 30, 2017, and, on April 28, 2017, ordered that the cases be held in abeyance for 60 days, with supplemental briefs required to be filed May 15, 2017, regarding whether the cases should be remanded to the EPA rather than held in abeyance. On August 10, 2017, the court placed the case in abeyance pending further orderfor 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. 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, 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. Because the significant contribution rule did not alter the emission limits or technology requirements of the court. Until such time as the court renders a final determination regarding the validity of the standards or the EPA rescinds the standards,2015 rule, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.

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Clean Power PlanNew 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 wells 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 2014,30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution has the effect of reinstating 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 released proposed regulationsrules in response to address GHGExecutive Order 13990. The November 2021 proposed rule would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposal 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 fossil-fueled generating facilities, referredsources nationwide. The EPA intends to asissue a supplemental proposal in 2022 and to finalize the Clean Power Plan, under Section 111(d)rule by the end of 2022. Until the rule is finalized, the relevant Registrants cannot determine the full impacts of the proposed rule.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act.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.

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 EPA's proposal calculated state-specific emission rate targetsrule utilizes source modeling in addition to be achieved basedthe 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 "Best SystemLouisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's or the Nevada Utilities' generating facilities, the EPA's assessment of Emission Reduction." In August 2015,SO2 area designations will continue with 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 EPA also changedadditional SO2 monitoring networks across the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030.country. On February 9, 2016, the United States Supreme Court ordered that the EPA's emission guidelines for existing sources be stayed pending the disposition of the challenges to the rule in the D.C. Circuit and any action on a writ of certiorari before the U.S. Supreme Court. Oral argument was heard before the full D.C. Circuit (with the exception of Chief Judge Merrick Garland) on September 27, 2016, and the court has not yet issued its decision. The case has been held in abeyance pending underlying action by the EPA. On October 10, 2017,25, 2019, the EPA issued a proposaldecision to repealretain the Clean Power Plan and the public comment period closes on the proposal December 15, 2017. EPA has not determined whether it will issue2010 SO2 NAAQS without revision.

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The Sierra Club filed a replacement rule. Until such time aslawsuit against the EPA takes final action onin August 2013 with respect to the repealone-hour SO2 standards and determines whether there will beits failure to make certain attainment designations in a replacement rule, the impact of EPA’s actions on the Registrants cannot be determined. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.



Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality intimely manner. In March 2015, the United States throughDistrict 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 require 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 programmajority 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 regulates, among other things, dischargesDes 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.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of NOxand withdrawalsSO2, precursors of ozone and particulate matter, from waterways. 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 Clean Water Act requires that cooling water intake structures reflectfirst phase of the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation,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, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. 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. 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 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 power plants 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 §316(b)the 2008 ozone NAAQS. Additional emissions reductions are required at power plants 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 largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule.

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 Water ActAir Visibility Rules. In accordance with the federal requirements, states are required to regulate cooling water intakes at existing facilities. 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.

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The final rulestate 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 released in May 2014, and became effectiveupheld on appeal by the Tenth Circuit Court of Appeals ("Tenth Circuit") in October 2014. UnderIn addition, 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 requiredEPA initially proposed in June 2012 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 watersdisapprove 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 must also conduct studiesDepartment of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to help their permitting authority determine what site-specific controls, if any, would be requiredinstall SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to reduce entrainment of aquatic organisms (i.e., when organisms are drawn intoa comment period which ended July 6, 2021. Litigation in 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 watersTenth Circuit remains stayed pending finalization of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby,settlement agreement.

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 generating facilities currently utilize closed cycle cooling towers but are designedUnits 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 withdraw more than two million gallonseither approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of water per day.SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The standards are required to be met as soon as possible afterEPA'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 FIP requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the final rule, but no later than eight years thereafter. The costs of compliancerule. PacifiCorp and other parties filed requests with the cooling water intake structure rule cannot be fully determined untilEPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the prescribed studies are conducted. InTenth Circuit asking the event that PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipatedcourt 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 tooverturn 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 guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal; the new limits were to have been met as soon as possible, beginning November 1, 2018 and 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 that 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. On September 18,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 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 plant enforceable under the SIP and removes the requirement to install SCR technology 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 plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1,approving the Utah Regional Haze SIP Alternative on October 28, 2020. While mostWith the approval, the EPA also finalized its withdrawal of the issues raised by this rule are already being addressed throughFIP requirements for the coal combustion residuals ruleHunter and are not expected to impose significant additional requirementsHuntington plants. 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 the facilities, the impactJanuary 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 rule cannot be fully determined untilUtah Regional Haze SIP Alternative in the reconsideration action is completeTenth Circuit. PacifiCorp and any judicialthe state of Utah moved to intervene in the litigation, which has been stayed pending the Biden administration's review is concluded.of the rule.

55

Water Quality Standards

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 comescame 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 is currently under appealwas appealed in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the U.S.United States Supreme Court granted a petition to address jurisdictional challenges to the rule. On June 27, 2017, the EPA initiated the repeal of the "waters of the United States" 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. The proposed repeal of the rule has not yet been published in the Federal Register. Depending on the outcome of the appeal(s) and intended rulemaking, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits would have been required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. On February 28, 2017, President Trump signed an Executive Order directing the EPA to review and rescind or revise the rule. 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. Untilrule, which was finalized September 12, 2019. On January 22, 2018, the outcome ofUnited States Supreme Court issued its decision related to the pending actions and any litigation is known, the Registrants cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.



Coal Combustion Byproduct Disposal

In May 2010, the EPA released a proposed rulejurisdictional challenges to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the RCRA. The public comment period closed in November 2010. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and became 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 coal combustion residuals. 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. On August 10, 2017, the EPA issued proposed permitting guidance on how states’ coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. The public comment period on the permitting guidance closed on September 14, 2017. Also, on September 14, 2017, the EPA granted reconsideration on aspects of the final rule. On September 18, 2017, the EPA filed a motion to hold the pending litigation on the final rule in abeyance; however, the D.C. Circuit has not made a final ruling on the motion. The D.C. Circuit requested additional briefing on the abeyance motion and directed the EPA to identify, by November 15, 2017, which issues it intends to reconsider and the timeframe for completion of the reconsideration process. Oral argument on the motion for abeyance is scheduled for November 20, 2017.

At the time the rule, was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfillsholding that contained coal combustion byproducts. Priorfederal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the effective daterule 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 October 2015, nine surfacecertain 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, 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 three landfillsthe 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 either closed or repurposedin 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 receive coal combustion byproductsimplement 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 hence are not subjectthose 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 final rule. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contained 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. These six impoundments are subject to closure on or before April 2018. At the time the rule was published in April 2015, the Nevada Utilities operated ten 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 and are subject to final closure on or before April 2018, and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016 and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016 for discussion of the impacts on asset retirement obligations as a result of the final rule.relevant Registrants cannot be determined.


New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016.2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2016.2020.




56

PacifiCorp and its subsidiaries
Consolidated Financial Section




57

PART I
Item 1.Financial Statements

Item 1.Financial Statements



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Shareholders of
PacifiCorp
Portland, Oregon

Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2017, and2021, the related consolidated statements of operations and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, and of changes in shareholders' equity and cash flowsfor the nine-month periods ended September 30, 20172021 and 2016. These2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements areinformation for it to be in conformity with accounting principles generally accepted in the responsibilityUnited States of PacifiCorp's management.America.


We conducted our reviewshave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2020, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results
This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States),PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP


Portland, Oregon
November 3, 20175, 2021




58

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)


 As of
 September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$893 $13 
Trade receivables, net732 703 
Other receivables, net41 48 
Inventories465 482 
Derivative contracts153 27 
Regulatory assets70 116 
Prepaid expenses89 79 
Other current assets24 55 
Total current assets2,467 1,523 
 
Property, plant and equipment, net22,748 22,430 
Regulatory assets1,326 1,279 
Other assets530 470 
 
Total assets$27,071 $25,702 
  As of
  September 30, December 31,
  2017 2016
ASSETS
Current assets:    
Cash and cash equivalents $104
 $17
Accounts receivable, net 722
 728
Income taxes receivable —
 17
Inventories:    
Materials and supplies 237
 228
Fuel 207
 215
Regulatory assets 30
 53
Other current assets 72
 96
Total current assets 1,372
 1,354
     
Property, plant and equipment, net 19,135
 19,162
Regulatory assets 1,518
 1,490
Other assets 388
 388
     
Total assets $22,413
 $22,394


The accompanying notes are an integral part of these consolidated financial statements.

59


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)


 As of
 September 30,December 31,
20212020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable$624 $772 
Accrued interest115 127 
Accrued property, income and other taxes159 80 
Accrued employee expenses117 84 
Short-term debt— 93 
Current portion of long-term debt574 420 
Regulatory liabilities112 115 
Other current liabilities241 174 
Total current liabilities1,942 1,865 
 
Long-term debt8,625 8,192 
Regulatory liabilities2,759 2,727 
Deferred income taxes2,781 2,627 
Other long-term liabilities1,064 1,118 
Total liabilities17,171 16,529 
 
Commitments and contingencies (Note 9)00
 
Shareholders' equity:
Preferred stock2 2 
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding— — 
Additional paid-in capital4,479 4,479 
Retained earnings5,437 4,711 
Accumulated other comprehensive loss, net(18)(19)
Total shareholders' equity9,900 9,173 
 
Total liabilities and shareholders' equity$27,071 $25,702 
  As of
  September 30, December 31,
  2017 2016
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:    
Accounts payable $398
 $408
Income taxes payable 64
 —
Accrued employee expenses 115
 67
Accrued interest 106
 115
Accrued property and other taxes 136
 63
Short-term debt —
 270
Current portion of long-term debt and capital lease obligations 591
 58
Regulatory liabilities 67
 54
Other current liabilities 164
 164
Total current liabilities 1,641
 1,199
     
Regulatory liabilities 1,032
 978
Long-term debt and capital lease obligations 6,436
 7,021
Deferred income taxes 4,884
 4,880
Other long-term liabilities 913
 926
Total liabilities 14,906
 15,004
     
Commitments and contingencies (Note 8)    
     
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 3,038
 2,921
Accumulated other comprehensive loss, net (12) (12)
Total shareholders' equity 7,507
 7,390
     
Total liabilities and shareholders' equity $22,413
 $22,394


The accompanying notes are an integral part of these consolidated financial statements.




60

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)


 Three-Month PeriodsNine-Month Periods
 Ended September 30,Ended September 30,
 2021202020212020
 
Operating revenue$1,491 $1,479 $4,031 $3,829 
   
Operating expenses:
Cost of fuel and energy505 499 1,370 1,299 
Operations and maintenance267 332 781 829 
Depreciation and amortization272 234 811 696 
Property and other taxes54 53 158 154 
Total operating expenses1,098 1,118 3,120 2,978 
   
Operating income393 361 911 851 
   
Other income (expense):  
Interest expense(110)(107)(322)(319)
Allowance for borrowed funds6 14 18 36 
Allowance for equity funds13 29 38 73 
Interest and dividend income7 2 18 8 
Other, net(5)5 5 9 
Total other income (expense)(89)(57)(243)(193)
   
Income before income tax (benefit) expense304 304 668 658 
Income tax (benefit) expense(28)18 (58)30 
Net income$332 $286 $726 $628 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Operating revenue$1,430
 $1,434
 $3,956
 $3,919
        
Operating costs and expenses:       
Energy costs465
 478
 1,305
 1,295
Operations and maintenance248
 272
 754
 800
Depreciation and amortization200
 193
 598
 576
Taxes, other than income taxes50
 47
 149
 141
Total operating costs and expenses963
 990
 2,806
 2,812
        
Operating income467
 444
 1,150
 1,107
        
Other income (expense):       
Interest expense(95) (95) (285) (285)
Allowance for borrowed funds4
 4
 12
 12
Allowance for equity funds7
 7
 21
 21
Other, net6
 3
 13
 9
Total other income (expense)(78) (81) (239) (243)
        
Income before income tax expense389
 363
 911
 864
Income tax expense126
 110
 294
 270
Net income$263
 $253
 $617
 $594


The accompanying notes are an integral part of these consolidated financial statements.




61

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)


 Accumulated 
   Additional OtherTotal
PreferredCommonPaid-inRetainedComprehensiveShareholders'
 StockStockCapitalEarningsLoss, NetEquity
 
Balance, June 30, 2020$2 $— $4,479 $4,314 $(15)$8,780 
Net income— — — 286 — 286 
Balance, September 30, 2020$2 $— $4,479 $4,600 $(15)$9,066 
Balance, December 31, 2019$2 $— $4,479 $3,972 $(16)$8,437 
Net income— — — 628 — 628 
Other comprehensive income— — — — 1 1 
Balance, September 30, 2020$2 $— $4,479 $4,600 $(15)$9,066 
       
Balance, June 30, 2021$2 $— $4,479 $5,105 $(19)$9,567 
Net income— — — 332 — 332 
Other comprehensive income— — — — 1 1 
Balance, September 30, 2021$2 $— $4,479 $5,437 $(18)$9,900 
Balance, December 31, 2020$2 $— $4,479 $4,711 $(19)$9,173 
Net income— — — 726 — 726 
Other comprehensive income— — — — 1 1 
Balance, September 30, 2021$2 $— $4,479 $5,437 $(18)$9,900 
          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 —
 —
 —
 594
 —
 594
Common stock dividends declared —
 —
 —
 (550) —
 (550)
Balance, September 30, 2016 $2
 $—
 $4,479
 $3,077
 $(11) $7,547
   
  
  
  
  
  
Balance, December 31, 2016 $2
 $—
 $4,479
 $2,921
 $(12) $7,390
Net income —
 —
 —
 617
 —
 617
Common stock dividends declared —
 —
 —
 (500) —
 (500)
Balance, September 30, 2017 $2
 $—
 $4,479
 $3,038
 $(12) $7,507


The accompanying notes are an integral part of these consolidated financial statements.




62

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)


 Nine-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 20212020
Cash flows from operating activities:    Cash flows from operating activities: 
Net income $617
 $594
Net income$726  $628 
Adjustments to reconcile net income to net cash flows from operating activities:    Adjustments to reconcile net income to net cash flows from operating activities: 
Depreciation and amortization 598
 576
Depreciation and amortization811  696 
Allowance for equity funds (21) (21)Allowance for equity funds(38)(73)
Changes in regulatory assets and liabilitiesChanges in regulatory assets and liabilities(185) (17)
Deferred income taxes and amortization of investment tax credits 14
 76
Deferred income taxes and amortization of investment tax credits33  (48)
Changes in regulatory assets and liabilities 21
 85
Other, net 1
 6
Other, net— 2 
Changes in other operating assets and liabilities:    
Changes in other operating assets and liabilities:  
Accounts receivable and other assets 25
 19
Trade receivables, other receivables and other assetsTrade receivables, other receivables and other assets(1) (150)
InventoriesInventories17  (97)
Derivative collateral, net (4) 2
Derivative collateral, net19  22 
Inventories (1) (32)
Income taxes 75
 133
Prepaid expensesPrepaid expenses(11)(4)
Accrued property, income and other taxes, netAccrued property, income and other taxes, net96 84 
Accounts payable and other liabilities 110
 (66)Accounts payable and other liabilities77  248 
Net cash flows from operating activities 1,435
 1,372
Net cash flows from operating activities1,544  1,291 
    
   
Cash flows from investing activities:    
Cash flows from investing activities:  
Capital expenditures (553) (586)Capital expenditures(1,157) (1,618)
Other, net 32
 26
Other, net7  31 
Net cash flows from investing activities (521) (560)Net cash flows from investing activities(1,150) (1,587)
    
   
Cash flows from financing activities:    
Cash flows from financing activities:  
Repayments of long-term debt and capital lease obligations (54) (56)
Net repayments of short-term debt (270) (20)
Common stock dividends (500) (550)
Proceeds from long-term debtProceeds from long-term debt984 987 
Repayments of long-term debtRepayments of long-term debt(400)— 
Repayments of short-term debtRepayments of short-term debt(93)(130)
Other, net (3) —
Other, net(5)— 
Net cash flows from financing activities (827) (626)Net cash flows from financing activities486  857 
    
   
Net change in cash and cash equivalents 87
 186
Cash and cash equivalents at beginning of period 17
 12
Cash and cash equivalents at end of period $104
 $198
Net change in cash and cash equivalents and restricted cash and cash equivalentsNet change in cash and cash equivalents and restricted cash and cash equivalents880  561 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of periodCash and cash equivalents and restricted cash and cash equivalents at beginning of period19  36 
Cash and cash equivalents and restricted cash and cash equivalents at end of periodCash and cash equivalents and restricted cash and cash equivalents at end of period$899  $597 
 
The accompanying notes are an integral part of these consolidated financial statements.




63

PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(1)    General


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").


The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 20172021 and for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The results of operations for the three- and nine-month periods ended September 30, 20172021 and 20162020 are not necessarily indicative of the results to be expected for the full year.


The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 20162020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2017.2021.


(2)    New Accounting PronouncementsCash and Cash Equivalents and Restricted Cash and Cash Equivalents


In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendmentsCash equivalents consist of funds invested in this guidance require that an employer disaggregate the service cost component from themoney market mutual funds, United States Treasury Bills and other componentsinvestments with a maturity of net benefit costthree months or less when purchased. Cash 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. PacifiCorp plans to adopt this guidance effective January 1, 2018. PacifiCorp does not believe this will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.



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 andexclude amounts generally described aswhere availability is restricted cashby legal requirements, loan agreements or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included withother contractual provisions. Restricted cash and cash equivalents when reconciling the beginning-of-periodconsist substantially of funds representing vendor retention, custodial and end-of-period totalnuclear decommissioning funds. Restricted amounts shownare included in other current assets and other assets on the statementConsolidated Balance Sheets. A reconciliation of cash flows. This guidance is effective for interim and annual reporting periods beginning aftercash equivalents and restricted cash and cash equivalents as of September 30, 2021 and December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. PacifiCorp plans to adopt this guidance effective January 1, 2018 and does not believe31, 2020, as presented in the adoption of this guidance will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendmentsFlows is outlined below and disaggregated by the line items 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. PacifiCorp plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will 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 liabilitiesthey appear 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. 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 plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.Balance Sheets (in millions):

As of
September 30,December 31,
20212020
Cash and cash equivalents$893 $13 
Restricted cash included in other current assets4 4 
Restricted cash included in other assets2 2 
Total cash and cash equivalents and restricted cash and cash equivalents$899 $19 
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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. PacifiCorp does not believe this 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 creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize 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. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. PacifiCorp plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. PacifiCorp currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp’s performance to date. PacifiCorp plans to quantitatively disaggregate revenue in the required financial statement footnote by customer class.
64





(3)    Property, Plant and Equipment, Net


Property, plant and equipment, net consists of the following (in millions):
  As of
 September 30,December 31,
Depreciable Life20212020
Utility Plant: 
Generation15 - 59 years$13,635 $12,861 
Transmission60 - 90 years7,833 7,632 
Distribution20 - 75 years7,889 7,660 
Intangible plant(1)
5 - 75 years1,083 1,054 
Other5 - 60 years1,535 1,510 
Utility plant in service31,975 30,717 
Accumulated depreciation and amortization (10,370)(9,838)
Utility plant in service, net 21,605 20,879 
Other non-regulated, net of accumulated depreciation and amortization14 - 95 years9 9 
Plant, net21,614 20,888 
Construction work-in-progress 1,134 1,542 
Property, plant and equipment, net $22,748 $22,430 
   As of
   September 30, December 31,
 Depreciable Life 2017 2016
      
Property, plant and equipment in-service5-75 years $27,599
 $27,298
Accumulated depreciation and amortization  (9,222) (8,793)
Net property, plant and equipment in-service  18,377
 18,505
Construction work-in-progress  758
 657
Total property, plant and equipment, net  $19,135
 $19,162


(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.

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 $38 million for the three-month period ended September 30, 2021 as compared to the three-month period ended September 30, 2020, and $120 million for the nine-month period ended September 30, 2021 compared to the nine-month period ended September 30, 2020 based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.

(4)    Recent Financing Transactions


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.

Credit Facilities

In June 2017,2021, PacifiCorp extended, withterminated, upon lender consent, the maturity date to June 2020 for its $400 million unsecured credit facility by exercising the first of two available one-year extensions.

In June 2017, PacifiCorp terminated itsexisting $600 million unsecured credit facility expiring March 2018in June 2022. In June 2021, PacifiCorp amended and entered into arestated its other existing $600 million unsecured credit facility expiring in June 20202022 with twoone 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.


These creditCommon Shareholder's Equity

In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.
65

(5)    Income Taxes

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:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
State income tax, net of federal income tax benefit4 3 4 3 
Federal income tax credits(20)(15)(20)(12)
Effects of ratemaking(13)(4)(14)(8)
Other(1)1 — 1 
Effective income tax rate(9)%6 %(9)%5 %

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 which supportis 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 for the three- and nine-month periods ended September 30, 2021, and 2020 is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $89 million for the nine-month period ended September 30, 2021, including the use of $3 million to amortize certain regulatory asset balances in Wyoming, as compared to $41 million for the nine-month period endedSeptember 30, 2020, including the use of $30 million to accelerate depreciation of certain retired equipment in Oregon. Excess deferred income tax amortization, net of deferrals, was $41 million for the three-month period ended September 30, 2021, as compared to $6 million for the three-month period ended September 30, 2020.

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's commercial paper programprovision for federal and certain seriesstate income tax has been computed on a stand-alone basis, and substantially all of its tax-exempt bond obligationscurrently payable or receivable income tax is remitted to or received from BHE. For the nine-month period ended September 30, 2021 PacifiCorp received net cash payments for federal and providestate income tax from BHE totaling $109 million. For the nine-month period ended September 30, 2020 PacifiCorp made net cash payments for the issuance of letters of credit, have 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. These credit facilities require PacifiCorp's ratio of consolidated debt, including current maturities,federal and state income tax to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.BHE totaling $79 million.


66
(5)

(6)    Employee Benefit Plans


Net periodic benefit cost (credit) cost for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Pension:
Service cost$— $— $— $— 
Interest cost8 9 22 27 
Expected return on plan assets(12)(14)(39)(42)
Settlement4 — 4 — 
Net amortization5 4 15 13 
Net periodic benefit cost (credit)$5 $(1)$2 $(2)
Other postretirement:
Service cost$— $— $1 $1 
Interest cost1 2 5 7 
Expected return on plan assets(2)(3)(6)(10)
Net amortization1 — 1 — 
Net periodic benefit (credit) cost$— $(1)$1 $(2)
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Pension:       
Service cost$—
 $1
 $—
 $3
Interest cost12
 14
 37
 41
Expected return on plan assets(18) (18) (54) (56)
Net amortization3
 8
 10
 25
Net periodic benefit (credit) cost$(3) $5
 $(7) $13
        
Other postretirement:       
Service cost$1
 $1
 $2
 $2
Interest cost3
 3
 10
 11
Expected return on plan assets(5) (5) (16) (16)
Net amortization(1) (1) (4) (4)
Net periodic benefit credit$(2) $(2) $(8) $(7)


Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $5$4 million and $-$1 million, respectively, during 2017.2021. As of September 30, 2017,2021, $3 million and $- million of contributions had been made to the pension plans.

The amount of lump sum pension distributions in 2021 resulted in a July 31, 2021 remeasurement of the pension plan assets and other postretirementprojected benefit plans, respectively.obligation. As a result of the remeasurement, PacifiCorp recognized a settlement loss of $4 million, net of regulatory deferrals. Additionally, the pension plan's underfunded status and regulatory asset each decreased by $84 million.





(6)(7)    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 regulated 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 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, 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 Note 78 for additional information on derivative contracts.

67

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):
OtherOtherOther 
CurrentOtherCurrentLong-term
AssetsAssetsLiabilitiesLiabilitiesTotal
As of September 30, 2021
Not designated as hedging contracts(1):
Commodity assets$159 $40 $4 $1 $204 
Commodity liabilities— — (46)(9)(55)
Total159 40 (42)(8)149 
     
Total derivatives159 40 (42)(8)149 
Cash collateral (payable) receivable(6)— 11 — 5 
Total derivatives - net basis$153 $40 $(31)$(8)$154 
As of December 31, 2020
Not designated as hedging contracts(1):
Commodity assets$29 $6 $1 $— $36 
Commodity liabilities(2)— (23)(28)(53)
Total27 6 (22)(28)(17)
      
Total derivatives27 6 (22)(28)(17)
Cash collateral receivable— — 15 9 24 
Total derivatives - net basis$27 $6 $(7)$(19)$7 
 Other   Other Other  
 Current Other Current Long-term  
 Assets Assets Liabilities Liabilities Total
          
As of September 30, 2017         
Not designated as hedging contracts(1):
         
Commodity assets$4
 $1
 $2
 $—
 $7
Commodity liabilities(1) —
 (24) (82) (107)
Total3
 1
 (22) (82) (100)
  
  
  
  
  
Total derivatives3
 1
 (22) (82) (100)
Cash collateral receivable—
 —
 16
 57
 73
Total derivatives - net basis$3
 $1
 $(6) $(25) $(27)
          
As of December 31, 2016         
Not designated as hedging contracts(1):
         
Commodity assets$24
 $2
 $1
 $—
 $27
Commodity liabilities(6) —
 (14) (84) (104)
Total18
 2
 (13) (84) (77)
          
Total derivatives18
 2
 (13) (84) (77)
Cash collateral receivable—
 —
 10
 59
 69
Total derivatives - net basis$18
 $2
 $(3) $(25) $(8)


(1)PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2017 and December 31, 2016, a regulatory asset of $97 million and $73 million, respectively, was recorded related to the net derivative liability of $100 million and $77 million, respectively.

(1)PacifiCorp's commodity derivatives are generally included in rates. As of September 30, 2021 a regulatory liability of $149 million was recorded related to the net derivative asset of $149 million. As of December 31, 2020 a regulatory asset of $17 million was recorded related to the net derivative liability of $17 million.


Not Designated as Hedging Contracts


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 (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Beginning balance$(102)$68 $17 $62 
Changes in fair value(128)(49)(247)(21)
Net gains (losses) reclassified to operating revenue— 1 (5)14 
Net gains (losses) reclassified to cost of fuel and energy81 (11)86 (46)
Ending balance$(149)$9 $(149)$9 

68
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Beginning balance$95
 $89
 $73
 $133
Changes in fair value recognized in net regulatory assets6
 15
 36
 (4)
Net (losses) gains reclassified to operating revenue(5) (2) 8
 8
Net gains (losses) reclassified to energy costs1
 —
 (20) (35)
Ending balance$97
 $102
 $97
 $102


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 (in millions):
Unit ofSeptember 30,December 31,
Measure20212020
Electricity sales, netMegawatt hours— (1)
Natural gas purchasesDecatherms101 100 
 Unit of September 30, December 31,
 Measure 2017 2016
      
Electricity salesMegawatt hours (3) (3)
Natural gas purchasesDecatherms 97
 84
Fuel oil purchasesGallons 2
 11


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-partythird‑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 three recognized credit rating agencies. These derivative contractsagreements 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 ofassurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2017,2021, PacifiCorp'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.


The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $102$54 million and $97$51 million as of September 30, 20172021 and December 31, 2016,2020, respectively, for which PacifiCorp had posted collateral of $73$11 million and $69$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 September 30, 20172021 and December 31, 2016,2020, PacifiCorp would have been required to post $26$36 million and $22$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.



69


(7)(8)    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 September 30, 2021    
Assets:    
Commodity derivatives$— $204 $— $(11)$193 
Money market mutual funds876 — — — 876 
Investment funds31 — — — 31 
 $907 $204 $— $(11)$1,100 
Liabilities - Commodity derivatives$— $(55)$— $16 $(39)
As of December 31, 2020
Assets:
Commodity derivatives$— $36 $— $(3)$33 
Money market mutual funds6 — — — 6 
Investment funds25 — — — 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 September 30, 2021 and December 31, 2020, respectively.

70
  Input Levels for Fair Value Measurements    
  Level 1 Level 2 Level 3 
Other(1) 
 Total
As of September 30, 2017          
Assets:          
Commodity derivatives $—
 $7
 $—
 $(3) $4
Money market mutual funds(2)
 100
 —
 —
 —
 100
Investment funds 20
 —
 —
 —
 20
  $120
 $7
 $—
 $(3) $124
           
Liabilities - Commodity derivatives $—
 $(107) $—
 $76
 $(31)
           
As of December 31, 2016          
Assets:          
Commodity derivatives $—
 $27
 $—
 $(7) $20
Money market mutual funds(2)
 13
 —
 —
 —
 13
Investment funds 17
 —
 —
 —
 17
  $30
 $27
 $—
 $(7) $50
           
Liabilities - Commodity derivatives $—
 $(104) $—
 $76
 $(28)


(1)Represents netting under master netting arrangements and a net cash collateral receivable of $73 million and $69 million as of September 30, 2017 and December 31, 2016, 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.



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 sixthree 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 sixthree 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 67 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 and are primarily accounted for as available-for-sale securities.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 (in millions):
 As of September 30, 2021As of December 31, 2020
 CarryingFairCarryingFair
 ValueValueValueValue
     
Long-term debt$9,199 $11,005 $8,612 $10,995 

  As of September 30, 2017 As of December 31, 2016
  Carrying Fair Carrying Fair
  Value Value Value Value
         
Long-term debt $7,005
 $8,277
 $7,052
 $8,204

(8)(9)    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.


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    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. 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.

As of September 30, 2021, 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 system is currently operating under annual licensesHydroelectric 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"). 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 the Klamath Hydroelectric Settlement Agreement ("KHSA").



Congress failed license to pass legislation needed to implement the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp anda third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC") jointly, who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

72

In September 2016, the KRRC and PacifiCorp filed ana joint application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilitiesdams from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with theThe FERC to surrender the license and decommission the 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 KRRC is effective.

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 are protected from uncapped dam removal costscustomers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and liabilities.the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC must indemnifyto file a new license transfer application by January 16, 2021, to remove 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,the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of which up to $184 million would be collected from PacifiCorp's Oregon customerssurrender. On January 13, 2021, the new license transfer application was filed with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measureFERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in November 2014 from which the state of California's contribution toward facilities removal costs are being drawn.new license transfer application. In accordance with this bond measure,addition, the MOA provides for additional contingency funding of up$45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to $250 million for facilities removal costs was includedequally share in any additional cost overruns in the California state budget in 2016, with the funding effective for at least five years. If facilitiesunlikely event that dam removal costs exceed the combined$450 million in funding that will be availableto 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'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 and the States as co-licensees. The transfer will be effective after PacifiCorp will resume relicensing withsecures property transfer approvals from its state public utility commissions and 30 days following the FERC.issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah.


Guarantees


PacifiCorp 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 PacifiCorp's consolidated financial results.


(9)     Related Party Transactions(10)    Revenue from Contracts with Customers


Berkshire Hathaway includes BHEThe following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Customer Revenue:
Retail:
Residential$530 $519 $1,442 $1,363 
Commercial428 418 1,180 1,122 
Industrial296 293 849 838 
Other retail98 114 214 209 
Total retail1,352 1,344 3,685 3,532 
Wholesale
58 59 124 76 
Transmission55 33 117 79 
Other Customer Revenue26 42 80 88 
Total Customer Revenue1,491 1,478 4,006 3,775 
Other revenue— 1 25 54 
Total operating revenue$1,491 $1,479 $4,031 $3,829 

73

Item 2.Management's Discussion and its subsidiaries in its 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,Analysis of Financial Condition and substantially allResults of its currently payable or receivable income taxes are remitted to or received from BHE. For the nine-month periods ended September 30, 2017 and 2016, PacifiCorp made net cash payments for federal and state income taxes to BHE totaling $205 million and $61 million, respectively.Operations



Item 2.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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.


Results of Operations for the Third Quarter and First Nine Months of 20172021 and 20162020

Overview


Net income for the third quarter of 20172021 was $263$332 million, an increase of $10$46 million, or 4%16%, compared to 2016.2020. Net income increased primarily due to higher gross margins of $30 million, excluding the impact of demand side management program revenue (offset inlower operations and maintenance expense)expense of $21$65 million, primarily due to prior year costs associated with the Klamath Hydroelectric Projectand estimated losses in the prior year associated with wildfires, lower income tax expense of $46 million primarily due to the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility margin of $6 million, partially offset by higher depreciation and amortization expense of $7$38 million, including the impacts of the depreciation study for which rates became effective January 2021, and lower allowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily from additional plant placed in-service. Gross margins increased due to higher retail customerand wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms, lower purchased electricity volumes lower coal costs, lower natural gas-fueled generation, and higher wheelingREC revenue, partially offset by higher purchased electricity prices, thermal generation costs, lower average retail rates and lower wholesale revenue, primarily due to lower volumes.wheeling expenses. Retail customer volumes increased 2.1%, primarily due to impacts of weather on residential customers, primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah, and an increase in the average number of residentialcustomers and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon.higher customer usage. Energy generated decreased 2%increased 9% for the third quarter of 20172021 compared to 20162020 primarily due to lowerhigher wind-powered, coal-fueled, and natural gas-fueled and wind-powered generation, partially offset by higherlower hydroelectric generation. Wholesale electricity sales volumes decreased 11%increased 4% and purchased electricity volumes increased 19%decreased 16%.


Net income for the first nine months of 20172021 was $617$726 million, an increase of $23$98 million, or 4%16%, compared to 2016.2020. Net income increased primarily due to higher gross marginsutility margin of $71$131 million, excludinglower income tax expense of $118 million (excluding prior year impacts of the impactOregon RAC settlement offset in depreciation expense), primarily from the impacts of demand side management program revenue (offset inratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, lower operations and maintenance expense)expense of $44$48 million, primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, partially offset by higher depreciation and amortization expense of $22$115 million, from additional plant placed in-serviceincluding the impacts of the depreciation study for which rates became effective January 2021, and higher property taxeslower allowances for equity and borrowed funds used during construction of $6$53 million. Gross marginsUtility margin increased primarily due to the higher retail, customer volumes,wholesale, and wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms, lower natural gas-fueled generation, higher wholesale revenue from higher short-term market prices andpurchased electricity volumes and higher wheelingREC revenue, partially offset by higher purchased electricity prices, thermal generation costs from higher volumes and prices, and lower average retail rates.wheeling expenses. Retail customer volumes increased 2.4%4.4%, primarily due to impacts of weather, primarily on residential customers in Oregon, Washington and Utah, higher commercialcustomer usage, primarily in Oregon, an increase in the average number of residentialcustomers, and commercial customers, primarily in Utah and Oregon, and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho.favorable impacts of weather. Energy generated decreased 2%increased 14% for the first nine months of 20172021 compared to 20162020 primarily due to lowerhigher coal-fueled, wind-powered, and natural gas-fueled and wind-powered generation, partially offset by higherlower hydroelectric and coal generation. Wholesale electricity sales volumes decreased 3%increased 20% and purchased electricity volumes increased 20%decreased 16%.


OperatingNon-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, costswhich are captions presented on the key driversConsolidated Statements of Operations.

PacifiCorp's resultscost of operationsfuel and energy is generally recovered from its customers through regulatory recovery mechanisms and as they encompass retaila result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and wholesale electricity revenue and the direct costs associated with providing electricity to customers. PacifiCorp believes thatconcisely explains profitability rather than a discussion of grossrevenue and cost of fuel and energy separately. Management believes the presentation of utility margin representingprovides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

74

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 revenue less energy costs,income which is therefore meaningful.the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):

Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin:
Operating revenue$1,491 $1,479 $12 1 %$4,031 $3,829 $202 5 %
Cost of fuel and energy505 499 6 1 1,370 1,299 71 5 
Utility margin986 980 6 1 2,661 2,530 131 5 
Operations and maintenance267 332 (65)(20)781 829 (48)(6)
Depreciation and amortization272 234 38 16 811 696 115 17 
Property and other taxes54 53 1 2 158 154 4 3 
Operating income$393 $361 $32 9 %$911 $851 $60 7 %

75


Utility Margin

A comparison of PacifiCorp's key operating results related to utility margin is as follows:
Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$1,491 $1,479 $12 1 %$4,031 $3,829 $202 5 %
Cost of fuel and energy505 499 6 1 1,370 1,299 71 5 
Utility margin$986 $980 $6 1 %$2,661 $2,530 $131 5 %
Sales (GWhs):
Residential4,732 4,622 110 2 %13,396 12,699 697 5 %
Commercial5,078 4,799 279 6 14,181 13,157 1,024 8 
Industrial, irrigation and other5,375 5,446 (71)(1)14,976 14,907 69 — 
Total retail15,185 14,867 318 2 42,553 40,763 1,790 4 
Wholesale1,093 1,053 40 4 3,928 3,266 662 20 
Total sales16,278 15,920 358 2 %46,481 44,029 2,452 6 %
Average number of retail customers
 (in thousands)		2,006 1,971 35 2 %1,998 1,963 35 2 %
Average revenue per MWh:
Retail$88.91 $90.25 $(1.34)(1)%$86.53 $86.60 $(0.07)— %
Wholesale$53.45 $57.54 $(4.09)(7)%$37.23 $38.58 $(1.35)(3)%
Heating degree days196 194 2 1 %6,111 6,132 (21)— %
Cooling degree days1,681 1,658 23 1 %2,427 2,097 330 16 %
Sources of energy (GWhs)(1):
Coal9,011 8,576 435 5 %24,157 22,001 2,156 10 %
Natural gas3,886 3,638 248 7 10,174 8,881 1,293 15 
Hydroelectric(2)
380 414 (34)(8)1,981 2,351 (370)(16)
Wind and other(2)
1,323 720 603 84 4,534 2,696 1,838 68 
Total energy generated14,600 13,348 1,252 9 40,846 35,929 4,917 14 
Energy purchased3,058 3,621 (563)(16)9,407 11,245 (1,838)(16)
Total17,658 16,969 689 4 %50,253 47,174 3,079 7 %
Average cost of energy per MWh:
Energy generated(3)
$18.39 $18.65 $(0.26)(1)%$17.98 $17.95 $0.03 — %
Energy purchased$88.48 $53.28 $35.20 66 %$67.10 $45.85 $21.25 46 %

(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.
76

 Third Quarter First Nine Months
 2017 2016 Change 2017 2016 Change
Gross margin (in millions):               
Operating revenue$1,430
 $1,434
 $(4) — % $3,956
 $3,919
 $37
 1 %
Energy costs465
 478
 (13) (3)% 1,305
 1,295
 10
 1 %
Gross margin$965
 $956
 $9
 1 % $2,651
 $2,624
 $27
 1 %
                
Sales (GWh):               
Residential4,372
 4,147
 225
 5 % 12,410
 11,909
 501
 4 %
Commercial(1)
4,783
 4,544
 239
 5 % 13,303
 12,863
 440
 3 %
Industrial, irrigation and other(1)
5,683
 5,839
 (156) (3)% 16,061
 16,004
 57
 — %
Total retail14,838
 14,530
 308
 2 % 41,774
 40,776
 998
 2 %
Wholesale1,350
 1,513
 (163) (11)% 4,362
 4,493
 (131) (3)%
Total sales16,188
 16,043
 145
 1 % 46,136
 45,269
 867
 2 %
                
Average number of retail customers               
(in thousands)1,868
 1,842
 26
 1 % 1,863
 1,837
 26
 1 %
                
Average revenue per MWh:               
Retail$90.58
 $93.10
 $(2.52) (3)% $88.41
 $90.44
 $(2.03) (2)%
Wholesale$28.74
 $28.32
 $0.42
 1 % $29.55
 $25.41
 $4.14
 16 %
                
Heating degree days304
 236
 68
 29 % 6,472
 5,726
 746
 13 %
Cooling degree days1,804
 1,494
 310
 21 % 2,342
 2,051
 291
 14 %
                
Sources of energy (GWh)(2):
               
Coal10,764
 10,775
 (11) — % 27,120
 26,637
 483
 2 %
Natural gas2,486
 2,743
 (257) (9)% 5,647
 7,642
 (1,995) (26)%
Hydroelectric(3)
641
 488
 153
 31 % 3,598
 2,719
 879
 32 %
Wind and other(3)
460
 647
 (187) (29)% 2,030
 2,337
 (307) (13)%
Total energy generated14,351
 14,653
 (302) (2)% 38,395
 39,335
 (940) (2)%
Energy purchased3,023
 2,542
 481
 19 % 10,845
 9,031
 1,814
 20 %
Total17,374
 17,195
 179
 1 % 49,240
 48,366
 874
 2 %
                
Average cost of energy per MWh:               
Energy generated(4)
$19.89
 $20.86
 $(0.97) (5)% $19.21
 $19.36
 $(0.15) (1)%
Energy purchased$53.34
 $49.68
 $3.66
 7 % $42.20
 $43.02
 $(0.82) (2)%
Quarter Ended September 30, 2021 compared to Quarter Ended September 30, 2020

(1)Prior period GWh amounts have been reclassified for consistency with the current period presentation.

(2)GWh amounts are net of energy used by the related generating facilities.

(3)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.

(4)The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.




GrossUtility margin increased $9$6 million, or 1%, for the third quarter of 20172021 compared to 20162020 primarily due to:

•$38103 million of higher retail revenues due to increased volumes of 2.1% due to impacts of weather and higher usage, primarily in Utah and Oregon;

$28 million of higher net deferrals of incurreddeferred net power costs in accordance with established adjustment mechanisms;

•$2212 million of lower coal costs due to prior year charges related to damaged longwall mining equipment, and current quarter lower volumes; andfavorable wheeling activities;

•$78 million of lower natural gas costsincrease in retail revenue primarily due to higher customer volumes, partially offset by lower gas-fueled generation as gas prices wererates driven by certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers, and higher in 2017.customer usage, partially offset by the unfavorable impact of weather; and

•$6 million of higher REC, fly ash and by-product revenues.
The increases above were partially offset by:

•$80 million of higher purchased electricity costs from higher average market prices, partially offset by lower volumes;
•$3527 million of lower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense) in the prior year;
•$13 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes; and
•$7 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance decreased $65 million, or 20%, for the third quarter of 2021 compared to 2020 primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires and lower thermal plant maintenance expense, including overhauls, partially offset by higher wind plant and distribution maintenance.

Depreciation and amortization increased $38 million, or 16%, for the third quarter of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $38 million and higher plant in-service balances, partially offset by prior year accelerated depreciation of $27 million (offset in other revenue) due to the prior year Oregon RAC settlement.

Allowance for borrowed and equity funds decreased $24 million, or 56%, for the third quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.

Other, net decreased $10 million for the third quarter of 2021 compared to 2020 primarily due to the July 2021 pension settlement loss and market movements related to corporate-owned life insurance policies.

Income tax (benefit) expense decreased $46 million to a benefit of $28 million for the third quarter of 2021 compared to expense of $18 million for the third quarter of 2020. The effective tax rate was (9)% for 2021 and 6% for 2020. The effective tax rate decreased primarily as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year and increased PTCs from PacifiCorp's new wind-powered generating facilities.

First Nine Months of 2021 compared to First Nine Months of 2020

Utility margin increased $131 million, or 5%, for the first nine months of 2021 compared to 2020 primarily due to:
•$152 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers, and the favorable impact of weather;
•$151 million of higher deferred net power costs in accordance with established adjustment mechanisms;
•$21 million of favorable wheeling activities;
•$20 million of higher wholesale revenue due to higher wholesale volumes, partially offset by lower average wholesale market prices; and
•$18 million of higher REC, fly ash and by-product revenues.
77

The increases above were partially offset by:
•$117 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;
•$58 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes;

•$2234 million of lower average retail rates;

$21 million of lower demand side management programother revenue (offset in operations and maintenance expense), primarily driven by the recently implemented Utah Sustainable Transportation and Energy Plan ("STEP") program; and

$9 million of higher coal prices.

Operations and maintenance decreased $24 million, or 9%, for the third quarter of 2017 compared to 2016 primarily due to a decrease in demand side management program expense (offset in operating revenue) driven by the establishment of the Utah STEP program and a decrease in pension expense primarily due to a current year plan change.

Depreciation and amortization increased $7 million, or 4%, for the third quarter of 2017 compared to 2016 primarily due to higher plant-in-service.

Income tax expense increased $16 million, or 15%, for the third quarter of 2017 compared to 2016. The effective tax rate was 32% for 2017 and 30% for 2016. 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 period for certain wind-powered generating facilities.

Gross margin increased $27 million, or 1%, for the first nine months of 2017 compared to 2016 primarily due to:

$102 million of higher retail revenues due to increased customer volumes of 2.4% due to impacts of weather, primarily on residential customersthe Oregon RAC settlement (offset in Oregon, Washington and Utah, higher commercial usage primarily in Oregon, an increasedepreciation expense) in the average number of residentialprior year; and commercial customers, primarily in Utah and Oregon, and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho;

•$3633 million of higher net deferrals of incurred net powercoal-fueled generation costs in accordance with established adjustment mechanisms;

$28 million of lower natural gas costs primarily due to lower gas-fueled generation due to higher gas prices in 2017;

$20 million of lower coal costs due to prior year charges related to damaged longwall mining equipment;

$15 million of higher wholesale revenue due to higher short-term market prices and higher volumes; and

$13 million due to higher wheeling revenue, primarily due to higher volumes, and short-term prices.



The increases above were partially offset by:

$69 million of higher purchased electricity costs due to volumes and prices;

$49 million ofby lower average retail rates;prices.

$44 million of lower demand side management program revenue (offset in operations and maintenance expense), primarily driven by the recently implemented Utah STEP program; and

$24 million of higher coal costs due to higher prices and volumes.

Operations and maintenance decreased $46$48 million, or 6%, for the first nine months of 20172021 compared to 20162020 primarily due to a decreaseprior year costs associated with the Klamath Hydroelectric Project and estimated losses in demand side management programthe prior year associated with wildfires, lower thermal plant maintenance expense, (offset in operating revenue) driven by the establishment of the Utah STEP program,including overhauls, and a decrease in pension expense primarily due to a current year plan change. These decreases werelower employee expenses, partially offset by higher injurywind plant and damage expenses, primarily due to a prior year accrual for insurance proceeds,distribution maintenance and higher labor costs related to storm damage restoration.vegetation management costs.


Depreciation and amortizationincreased $22$115 million, or 4%17%, for the first nine months of 20172021 compared to 20162020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $120 million, and higher plant-in-service.plant in-service balances, partially offset by a $71 million decrease due to the prior year Oregon RAC settlement ($3 million in the first quarter of 2021 (fully offset in other revenue) compared to $74 million in 2020 ($34 million offset in other revenue and $40 million offset in income tax expense)).


Taxes, other than income taxes increased $8Allowance for borrowed and equity funds decreased $53 million, or 6% for the first nine months of 2017 compared to 2016 due to higher assessed property values.

Income tax expense increased $24 million, or 9%49%, for the first nine months of 20172021 compared to 20162020 primarily due to lower qualified construction work-in-progress balances and allowance for borrowed and equity funds rates.

Income tax (benefit) expense decreased $88 million to a benefit of $58 million for the first nine months of 2021 compared to expense of $30 million the first nine months of 2020. The effective tax rate was 32%(9)% for 2021 and 31%5% for 2017 and 2016, respectively.2020. The effective tax rate increaseddecreased 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 period for certainincreased PTCs from PacifiCorp's new wind-powered generating facilities.facilities and as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year.


Liquidity and Capital Resources

As of September 30, 2017,2021, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents $104
   
Credit facilities 1,000
Less:  
Short-term debt —
Tax-exempt bond support (130)
Net credit facilities 870
   
Total net liquidity $974
   
Credit facilities:  
Maturity dates 2020
Cash and cash equivalents$893 
Credit facilities1,200 
Less:
Tax-exempt bond support(218)
Net credit facilities982 
Total net liquidity$1,875 
Credit facilities:
Maturity dates2024 
Operating Activities


Net cash flows from operating activities for the nine-month periods ended September 30, 20172021 and 20162020 were $1,435$1,544 million and $1,372$1,291 million, respectively. The change was primarily due to the payment for USA Power final judgment and post-judgment interest in the prior year, higher receiptscollections from wholesale and retail customers and lower fuel payments,higher cash received for income taxes, partially offset by current year higher cash payments for income taxes and purchased power.wholesale purchases.



In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% in 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. As a result of PATH, PacifiCorp's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019.


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 and assumptions for each payment date.


78

Investing Activities


Net cash flows from investing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $(521)$(1,150) million and $(560)$(1,587) million, respectively. The change mainly reflectsis primarily due to a current year decrease in capital expenditures of $33 million.$461 million, partially offset by prior year proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015. Refer to "Future Uses of Cash" for discussion of capital expenditures.


Financing Activities


Net cash flows from financing activities for the nine-month period ended September 30, 2017 was $(827)2021 were $486 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $984 million. Uses of cash consisted substantially of $500$400 million for common stock dividends paid to PPW Holdings LLC, $270the repayment of long-term debt and $93 million for the repayment of short-term debt and $50 million for the repayment of long-term debt.


Net cash flows from financing activities for the nine-month period ended September 30, 2016 was $(626)2020 were $857 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $987 million. Uses of cash consisted substantially of $550 million for common stock dividends paid to PPW Holdings LLC, $54 million for the repayment of long-term debt and $20$130 million for the repayment of short-term debt.

Short-term Debt


Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2017,2021, PacifiCorp had no short-term debt outstanding. As of December 31, 2016,2020, PacifiCorp had $270$93 million of short-term debt outstanding at a weighted average interest rate of 0.96%0.16%.


Long-term Debt

In November 2021, PacifiCorp currentlyexercised 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.

Debt Authorizations

Following the July 2021 long-term debt issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $1.3$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.


AsCommon Shareholder's Equity

In October 2021, PacifiCorp declared a common stock dividend of September 30, 2017, PacifiCorp had $216$150 million, of letters of credit providing credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $213 million plus interest. These letters of credit were fully available as of September 30, 2017 and expire periodically through March 2019.payable in November 2021, to PPW Holdings LLC.


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 and conditions in the overall capital markets, including the condition of the utility industry.


79

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; 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.




Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Wind generation$807 $110 $138 
Electric distribution360 461 637 
Electric transmission300 212 316 
Other151 374 467 
Total$1,618 $1,157 $1,558 
 Nine-Month Periods Annual
 Ended September 30, Forecast
 2016 2017 2017
      
Transmission system investment$68
 $75
 $118
Environmental42
 18
 28
Wind investment—
 8
 8
Operating and other476
 452
 644
Total$586
 $553
 $798


PacifiCorp's 2019 and 2021 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate for these new resources and associated transmission in its forecast capital expenditures for 2021 through 2023. These estimates may 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 totaling $99 million and $705 million for the nine-month periods ended September 30, 2021 and 2020, respectively. 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 the first nine months of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals $17 million for the remainder of 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $9 million and $99 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for the repowering of wind-powered generating facilities totals $7 million for the remainder of 2021.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $144 million and $21 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned electric distribution spending totals $51 million for the remainder of 2021 and relates to expenditures for new connections and distribution.

•Electric transmission includes both growth projects and operating expenditures. Transmission system investment through 2020 primarily reflects main grid reinforcement costs and initial costs for the 140-mile 500 kV500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp’sPacifiCorp's Energy Gateway Transmission expansion program, expected to be placed in-service in November 2020. Planned spending for the Aeolus-Bridger/Anticline lineadditional Energy Gateway Transmission segments to be placed in service in 2024-2026 totals $16$46 million in 2017.2021.


Environmental
80

•Other includes the installation of new or the replacement of existing emissions control equipment at certain generating facilities, including installation or upgrade of selective catalytic reduction control systemsboth growth projects and low nitrogen oxide burners to reduce nitrogen oxides, particulate matter control systems, sulfur dioxide emissions control systemsoperating expenditures. Expenditures for information technology totaled $69 million and mercury emissions control systems, as well as expenditures$53 million for the managementnine-month periods ended September 30, 2021 and 2020, respectively. Planned information technology spending totals $47 million for the remainder of coal combustion residuals.

Remaining investments relate2021 and relates to operating projects that consist of routine expenditures for generation transmission, distribution and other infrastructure needed to serve existing and expected demand, including upgradesdemand.

Energy Supply Planning

As required by certain state regulations, PacifiCorp uses an IRP to customer meters in Oregon, Californiadevelop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and Idaho.cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations.

Integrated Resource Plan


In April 2017,September 2021, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP")2021 IRP with its state commissions. The IRP includes investments in new renewable energy resources, upgradesnew battery storage resources and expanded transmission investments. New renewable energy resources in the IRP include more than 1,800 MW of new wind-powered generation, over 2,100 MW of new solar-powered generation and nearly 700 MW of new battery storage capacity by 2025. The IRP also outlines PacifiCorp's plan to retire or convert to natural gas all coal-fueled resources by 2042.

Requests for Proposals

PacifiCorp issues individual RFPs to procure resources identified in the existing wind fleet,IRP or resources driven by customer demands. The IRP and energy efficiency measuresthe RFPs provide for the identification and staged procurement of resources to meet future customer needs. Implementation of wind upgrades, new transmission and new wind renewable resources will require an estimated $3 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million fromload or state-specific compliance obligations. Depending upon the forecast included in PacifiCorp's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.

Request for Proposals

As required byspecific RFP, applicable laws and regulations may require PacifiCorp filed itsto file draft 2017R Request for Proposals ("RFP")RFPs with the UPSC, in June 2017 and with the OPUC in August 2017. The UPSC and the WUTC. Approval by the UPSC, the OPUC approved PacifiCorp’s 2017Ror the WUTC may be required depending on the nature of the RFPs.

PacifiCorp issued the 2020 All Source RFP in September 2017. The 2017R RFP was subsequently released to the market on September 27, 2017.in July 2020. The 2017R2020 All Source RFP is seekingsought bids for resources capable of coming online by the end of 2024 up to 1,270 MWthe level of resources identified in PacifiCorp's 2019 IRP. An initial shortlist was identified in October 2020. The final shortlist of winning bids was submitted to OPUC in June 2021. PacifiCorp will initiate negotiations with shortlisted bids that include approximately 1,792 MWs of new wind resourcescapacity, 1,306 MWs of solar capacity and 697 MWs of battery storage to its portfolio by 2024. PacifiCorp expects that can interconnect to PacifiCorp’s transmission system in Wyoming once a proposed high-voltage transmission line is constructed. The 2017R RFP is also seeking proposals for wind resources located outside590 MWs of Wyoming capablethe 1,792 MWs of delivering all-in economic benefits for PacifiCorp's customers. The proposed high-voltage transmission line and new wind resources mustcapacity will be placed in service by December 31, 2020, to maximize potential federal production tax credit benefits for PacifiCorp's customers. Bids were due in October 2017.owned with the remainder of the wind, solar and battery storage capacity being contracted resources.


Contractual Obligations


As of September 30, 2017,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2016.2020.


Regulatory Matters


PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's 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, RPS, 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. 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 the EPAvarious federal, state and various state, local and international 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 "Liquidity and Capital Resources" for discussion of PacifiCorp's forecast environmental-related capital expenditures.


Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws.laws and regulations.


81
New Accounting Pronouncements


For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of the Form 10-Q.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2016.2020. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2016.2020.

82



MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section




83

PART I
Item 1.Financial Statements

Item 1.Financial Statements



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the Board of Directors and Shareholder of
MidAmerican Energy Company
Des Moines, Iowa

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2017, and2021, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, and of changes in equity and cash flows for the nine-month periods ended September 30, 20172021 and 2016. These2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements areinformation for it to be in conformity with accounting principles generally accepted in the responsibilityUnited States of MidAmerican Energy's management.America.


We conducted our reviewshave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2020, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States),PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet of MidAmerican Energy Company as of December 31, 2016, and the related statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.



/s/ Deloitte & Touche LLP




Des Moines, Iowa
November 3, 20175, 2021




84

MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)


As of
September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$541 $38 
Trade receivables, net555 234 
Inventories244 278 
Other current assets142 73 
Total current assets1,482 623 
Property, plant and equipment, net19,773 19,279 
Regulatory assets479 392 
Investments and restricted investments975 911 
Other assets235 232 
Total assets$22,944 $21,437 
 As of
 September 30, December 31,
 2017 2016
ASSETS
Current assets:   
Cash and cash equivalents$512
 $14
Receivables, net312
 285
Income taxes receivable—
 9
Inventories235
 264
Other current assets21
 35
Total current assets1,080
 607
    
Property, plant and equipment, net13,587
 12,821
Regulatory assets1,335
 1,161
Investments and restricted cash and investments707
 653
Other assets193
 217
    
Total assets$16,902
 $15,459


The accompanying notes are an integral part of these financial statements.

85


MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)


As of
September 30,December 31,
20212020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$347 $408 
Accrued interest89 78 
Accrued property, income and other taxes242 161 
Other current liabilities226 183 
Total current liabilities904 830 
Long-term debt7,716 7,210 
Regulatory liabilities943 1,111 
Deferred income taxes3,407 3,054 
Asset retirement obligations677 709 
Other long-term liabilities495 458 
Total liabilities14,142 13,372 
Commitments and contingencies (Note 9)00
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding— — 
Additional paid-in capital561 561 
Retained earnings8,241 7,504 
Total shareholder's equity8,802 8,065 
Total liabilities and shareholder's equity$22,944 $21,437 
 As of
 September 30, December 31,
 2017 2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:   
Accounts payable$256
 $303
Accrued interest52
 45
Accrued property, income and other taxes228
 137
Short-term debt—
 99
Current portion of long-term debt350
 250
Other current liabilities158
 159
Total current liabilities1,044
 993
    
Long-term debt4,544
 4,051
Deferred income taxes3,781
 3,572
Regulatory liabilities927
 883
Asset retirement obligations515
 510
Other long-term liabilities307
 290
Total liabilities11,118
 10,299
    
Commitments and contingencies (Note 8)
 
    
Shareholder's equity:   
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding—
 —
Additional paid-in capital561
 561
Retained earnings5,223
 4,599
Total shareholder's equity5,784
 5,160
    
Total liabilities and shareholder's equity$16,902
 $15,459


The accompanying notes are an integral part of these financial statements.




86

MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Operating revenue:
Regulated electric$854 $728 $1,985 $1,717 
Regulated natural gas and other112 84 741 389 
Total operating revenue966 812 2,726 2,106 
Operating expenses:
Cost of fuel and energy163 115 417 266 
Cost of natural gas purchased for resale and other64 40 553 210 
Operations and maintenance200 212 577 559 
Depreciation and amortization218 180 634 531 
Property and other taxes34 33 107 102 
Total operating expenses679 580 2,288 1,668 
Operating income287 232 438 438 
Other income (expense):
Interest expense(76)(74)(224)(224)
Allowance for borrowed funds4 5 8 12 
Allowance for equity funds11 16 25 33 
Other, net8 14 34 30 
Total other income (expense)(53)(39)(157)(149)
Income before income tax benefit234 193 281 289 
Income tax benefit(143)(147)(456)(411)
Net income$377 $340 $737 $700 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Operating revenue:       
Regulated electric$707
 $692
 $1,677
 $1,572
Regulated gas and other106
 103
 489
 432
Total operating revenue813
 795
 2,166
 2,004
        
Operating costs and expenses:       
Cost of fuel, energy and capacity130
 130
 342
 312
Cost of gas sold and other54
 55
 288
 237
Operations and maintenance200
 180
 547
 510
Depreciation and amortization111
 118
 369
 338
Property and other taxes30
 28
 90
 84
Total operating costs and expenses525
 511
 1,636
 1,481
        
Operating income288
 284
 530
 523
        
Other income (expense):       
Interest expense(54) (50) (160) (147)
Allowance for borrowed funds4
 3
 9
 6
Allowance for equity funds11
 6
 25
 14
Other, net5
 3
 13
 8
Total other income (expense)(34) (38) (113) (119)
        
Income before income tax benefit254
 246
 417
 404
Income tax benefit(131) (74) (207) (123)
        
Net income$385
 $320
 $624
 $527


The accompanying notes are an integral part of these financial statements.




87

MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions)


Common StockAdditional Paid-in CapitalRetained
Earnings		Total Shareholder's
Equity
Balance, June 30, 2020$— $561 $7,039 $7,600 
Net income— — 340 340 
Balance, September 30, 2020$— $561 $7,379 $7,940 
Balance, December 31, 2019$— $561 $6,679 $7,240 
Net income— — 700 700 
Balance, September 30, 2020$— $561 $7,379 $7,940 
Balance, June 30, 2021$— $561 $7,865 $8,426 
Net income— — 377 377 
Other equity transactions— — (1)(1)
Balance, September 30, 2021$— $561 $8,241 $8,802 
Balance, December 31, 2020$— $561 $7,504 $8,065 
Net income— — 737 737 
Balance, September 30, 2021$— $561 $8,241 $8,802 
 
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, Net
 
Total
Equity
        
Balance, December 31, 2015$561
 $4,174
 $(30) $4,705
Net income—
 527
 —
 527
Other comprehensive income—
 —
 2
 2
Dividend—
 (117) 27
 (90)
Other equity transactions—
 (1) —
 (1)
Balance, September 30, 2016$561
 $4,583
 $(1) $5,143
        
Balance, December 31, 2016$561
 $4,599
 $—
 $5,160
Net income—
 624
 —
 624
Balance, September 30, 2017$561
 $5,223
 $—
 $5,784


The accompanying notes are an integral part of these financial statements.




88

MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)


Nine-Month Periods
Ended September 30,
20212020
Cash flows from operating activities:
Net income$737 $700 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization634 531 
Amortization of utility plant to other operating expenses26 25 
Allowance for equity funds(25)(33)
Deferred income taxes and investment tax credits, net121 76 
Settlements of asset retirement obligations(51)(55)
Other, net42 (1)
Changes in other operating assets and liabilities:
Trade receivables and other assets(331)(15)
Inventories34 (40)
Pension and other postretirement benefit plans2 (17)
Accrued property, income and other taxes, net80 (10)
Accounts payable and other liabilities21 48 
Net cash flows from operating activities1,290 1,209 
Cash flows from investing activities:
Capital expenditures(1,266)(1,341)
Purchases of marketable securities(166)(251)
Proceeds from sales of marketable securities163 244 
Other, net(7)9 
Net cash flows from investing activities(1,276)(1,339)
Cash flows from financing activities:
Proceeds from long-term debt492 — 
Repayments of long-term debt(1)— 
Other, net(2)(1)
Net cash flows from financing activities489 (1)
Net change in cash and cash equivalents and restricted cash and cash equivalents503 (131)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period45 330 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$548 $199 
 Nine-Month Periods
 Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income$624
 $527
Adjustments to reconcile net income to net cash flows from operating activities:   
Depreciation and amortization369
 338
Deferred income taxes and amortization of investment tax credits64
 113
Changes in other assets and liabilities28
 34
Other, net(23) (42)
Changes in other operating assets and liabilities:   
Receivables, net(28) (67)
Inventories29
 (26)
Derivative collateral, net3
 4
Contributions to pension and other postretirement benefit plans, net(8) (5)
Accounts payable(5) 14
Accrued property, income and other taxes, net98
 160
Other current assets and liabilities20
 30
Net cash flows from operating activities1,171
 1,080
    
Cash flows from investing activities:   
Utility construction expenditures(1,162) (1,129)
Purchases of available-for-sale securities(126) (96)
Proceeds from sales of available-for-sale securities127
 92
Other, net—
 5
Net cash flows from investing activities(1,161) (1,128)
    
Cash flows from financing activities:   
Proceeds from long-term debt842
 33
Repayments of long-term debt(255) (38)
Net repayments of short-term debt(99) —
Net cash flows from financing activities488
 (5)
    
Net change in cash and cash equivalents498
 (53)
Cash and cash equivalents at beginning of period14
 103
Cash and cash equivalents at end of period$512
 $50


The accompanying notes are an integral part of these financial statements.




89

MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)


(1)General

(1)    General

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").


The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2017,2021, and for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2021 and 2020. The results of operations for the three- and nine-month periods ended September 30, 2017,2021, are not necessarily indicative of the results to be expected for the full year.


The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2016,2020, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2017.2021.


(2)New Accounting Pronouncements

In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments(2)    Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in this guidance require that an employer disaggregate the service cost component from themoney market mutual funds, United States Treasury Bills and other componentsinvestments with a maturity of net benefit costthree months or less when purchased. Cash 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. MidAmerican Energy plans to adopt this guidance effective January 1, 2018. MidAmerican Energy does not believe this will have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.

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 andexclude amounts generally described aswhere availability is restricted cashby legal requirements, loan agreements or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents must be included withother contractual provisions. Restricted cash and cash equivalents when reconcilingas of September 30, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, as presented in the beginning-of-periodStatements of Cash Flows is outlined below and end-of-period total amounts showndisaggregated by the line items in which they appear on the statement of cash flows. This guidance is effective for interimBalance Sheets (in millions):
As of
September 30,December 31,
20212020
Cash and cash equivalents$541 $38 
Restricted cash and cash equivalents in other current assets7 7 
Total cash and cash equivalents and restricted cash and cash equivalents$548 $45 

90

(3)    Property, Plant and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy plans to adopt this guidance effective January 1, 2018, and does not believe the adoption of this guidance will 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy plans to adopt this guidance effective January 1, 2018, and does not believe the adoption of this guidance will have a material impact on its Financial Statements.Equipment, Net



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. 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 plans to adopt this guidance effective January 1, 2019, and is currently evaluating the 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements. MidAmerican Energy does not believe this 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 creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize 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. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. MidAmerican Energy plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Financial Statements and disclosures included within Notes to Financial Statements. MidAmerican Energy currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when MidAmerican Energy has the right to invoice as it corresponds directly with the value to the customer of MidAmerican Energy’s performance to date. MidAmerican Energy's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by jurisdiction for each segment.



(3)Property, Plant and Equipment, Net


Property, plant and equipment, net consists of the following (in millions):
As of
September 30,December 31,
Depreciable Life20212020
Utility plant in service, net:
Generation20-70 years$17,162 $16,980 
Transmission52-75 years2,415 2,365 
Electric distribution20-75 years4,522 4,369 
Natural gas distribution29-75 years2,011 1,955 
Utility plant in service26,110 25,669 
Accumulated depreciation and amortization(7,444)(6,902)
Utility plant in service, net18,666 18,767 
Nonregulated property, net:
Nonregulated property gross20-50 years7 7 
Accumulated depreciation and amortization(1)(1)
Nonregulated property, net6 6 
18,672 18,773 
Construction work-in-progress1,101 506 
Property, plant and equipment, net$19,773 $19,279 

(4)    Regulatory Matters
   As of
   September 30, December 31,
 Depreciable Life 2017 2016
Utility plant in service, net:     
Generation20-70 years $11,339
 $11,282
Transmission52-75 years 1,802
 1,726
Electric distribution20-75 years 3,297
 3,197
Gas distribution29-75 years 1,606
 1,565
Utility plant in service  18,044
 17,770
Accumulated depreciation and amortization  (5,765) (5,448)
Utility plant in service, net  12,279
 12,322
Nonregulated property, net:     
Nonregulated property gross20-50 years 7
 7
Accumulated depreciation and amortization  (1) (1)
Nonregulated property, net  6
 6
   12,285
 12,328
Construction work-in-progress  1,302
 493
Property, plant and equipment, net  $13,587
 $12,821


Natural Gas Purchased for Resale
During
In February 2021, severe cold weather over the fourth quartercentral United States caused disruptions in natural gas supply from the southern part of 2016,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 Iowa Utilities Board 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, revised its electricthe increased costs and gas depreciation rates based onlonger recovery period resulted in higher working capital requirements during 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 $34 million annually, or $9 million and $26 million for the three- and nine-month periodsperiod ended September 30, 2017, based on depreciable plant balances at the time of the change.2021.


(4)
91

(5)    Recent Financing Transactions


Long-Term Debt


In February 2017,July 2021, MidAmerican Energy issued $375$500 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. An amount equal to2052. MidAmerican Energy used the net proceeds was used to finance a portion of the capital expenditures, disbursed during the period from February 2, 2016July 22, 2019 to February 1, 2017,September 27, 2019, with respect to investments in MidAmerican Energy's 551-megawatt Wind X andits 2,000-megawatt Wind XI projects,project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.

In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.


Credit Facilities


In June 2017,2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring in 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 consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility expiring March 2018 and entered into a $900 million unsecured credit facility expiring June 2020 with two one-year extension options 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. The credit facility requires 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.in August 2021.




(5)(6)    Income Taxes


A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(44)(55)(143)(122)
State income tax, net of federal income tax impacts(26)(27)(27)(29)
Effects of ratemaking(12)(15)(13)(13)
Other, net— — — 1 
Effective income tax rate(61)%(76)%(162)%(142)%
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Federal statutory income tax rate35 % 35 % 35 % 35 %
Income tax credits(74) (58) (74) (58)
State income tax, net of federal income tax benefit(10) (6) (7) (4)
Effects of ratemaking(2) (1) (4) (3)
Other, net(1) —
 —
 —
Effective income tax rate(52)% (30)% (50)% (30)%


Income tax credits relate primarily to production tax credits ("PTCs") from 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. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. 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 three-month periods ended September 30, 2021 and 2020 totaled $103 million and $105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352 million, respectively.


Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax return.returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income taxestax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income taxes aretax is remitted to or received from BHE. 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 and assumptions for each payment date. MidAmerican Energy received net cash payments for income taxestax from BHE totaling $381$677 million and $416$500 million for the nine-month periods ended September 30, 20172021 and 2016,2020, respectively.


(6)Employee Benefit Plans

92

(7)    Employee Benefit Plans

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. 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.


Net periodic benefit cost (credit) cost for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Pension:
Service cost$5 $2 $15 $4 
Interest cost6 7 17 19 
Expected return on plan assets(9)(10)(28)(30)
Net amortization— — 1 1 
Net periodic benefit cost (credit)$2 $(1)$5 $(6)
Other postretirement:
Service cost$2 $1 $6 $3 
Interest cost2 2 6 5 
Expected return on plan assets(2)(4)(7)(10)
Net amortization(1)(1)(3)(4)
Net periodic benefit cost (credit)$1 $(2)$2 $(6)
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Pension:       
Service cost$2
 $3
 $7
 $8
Interest cost8
 8
 23
 25
Expected return on plan assets(11) (11) (33) (33)
Net amortization—
 —
 1
 1
Net periodic benefit (credit) cost$(1) $—
 $(2) $1
        
Other postretirement:       
Service cost$2
 $1
 $4
 $4
Interest cost3
 2
 7
 7
Expected return on plan assets(3) (3) (10) (10)
Net amortization(1) (1) (3) (3)
Net periodic benefit cost (credit)$1
 $(1) $(2) $(2)




Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $8$7 million and $1$12 million, respectively, during 2017.2021. As of September 30, 2017,2021, $5 million and $1$9 million of contributions had been made to the pension and other postretirement benefit plans, respectively.


(7)Fair Value Measurements

(8)    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.


93

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 1Level 2Level 3
Other(1)
Total
As of September 30, 2021:
Assets:
Commodity derivatives$1 $70 $4 $(7)$68 
Money market mutual funds543 — — — 543 
Debt securities:
United States government obligations228 — — — 228 
International government obligations— 2 — — 2 
Corporate obligations— 86 — — 86 
Municipal obligations— 3 — — 3 
Agency, asset and mortgage-backed obligations— 1 — — 1 
Equity securities:
United States companies398 — — — 398 
International companies8 — — — 8 
Investment funds23 — — — 23 
$1,201 $162 $4 $(7)$1,360 
Liabilities - commodity derivatives$(2)$(5)$(4)$7 $(4)

94

Input Levels for Fair Value Measurements
 Input Levels for Fair Value Measurements    Level 1Level 2Level 3
Other(1)
Total
 Level 1 Level 2 Level 3 
Other(1)
 Total
As of September 30, 2017:          
As of December 31, 2020:As of December 31, 2020:
Assets:          Assets:
Commodity derivatives $—
 $2
 $2
 $(2) $2
Commodity derivatives$— $4 $5 $(5)$4 
Money market mutual funds(2)
 520
 —
 —
 —
 520
Money market mutual fundsMoney market mutual funds41 — — — 41 
Debt securities:          Debt securities:
United States government obligations 168
 —
 —
 —
 168
United States government obligations200 — — — 200 
International government obligations —
 5
 —
 —
 5
International government obligations— 5 — — 5 
Corporate obligations —
 37
 —
 —
 37
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 270
 —
 —
 —
 270
United States companies381 — — — 381 
International companies 7
 —
 —
 —
 7
International companies9 — — — 9 
Investment funds 15
 —
 —
 —
 15
Investment funds17 — — — 17 
 $980
 $47
 $2
 $(2) $1,027
$648 $90 $5 $(5)$738 
          
Liabilities - commodity derivatives $—
 $(6) $(4) $2
 $(8)Liabilities - commodity derivatives$— $(4)$(3)$5 $(2)



  Input Levels for Fair Value Measurements    
  Level 1 Level 2 Level 3 
Other(1)
 Total
As of December 31, 2016:          
Assets:          
Commodity derivatives $—
 $9
 $1
 $(2) $8
Money market mutual funds(2)
 1
 —
 —
 —
 1
Debt securities:          
United States government obligations 161
 —
 —
 —
 161
International government obligations —
 3
 —
 —
 3
Corporate obligations —
 36
 —
 —
 36
Municipal obligations —
 2
 —
 —
 2
Agency, asset and mortgage-backed obligations —
 2
 —
 —
 2
Equity securities:          
United States companies 250
 —
 —
 —
 250
International companies 5
 —
 —
 —
 5
Investment funds 9
 —
 —
 —
 9
  $426
 $52
 $1
 $(2) $477
           
Liabilities - commodity derivatives $—
 $(3) $(3) $3
 $(3)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $-(1)Represents netting under master netting arrangements and a net cash collateral receivable of $— million and $1 million as of September 30, 2017 and December 31, 2016, respectively.
(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.
Derivative contracts are recorded on the Balance Sheets as either assets or liabilitiesof September 30, 2021 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 MidAmerican Energy transacts. When quoted prices for identical contracts are not available, MidAmerican Energy uses forward price curves. Forward price curves represent MidAmerican Energy's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. MidAmerican Energy 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 MidAmerican Energy. Market price quotations are generally readily obtainable for the applicable term of MidAmerican Energy's outstanding derivative contracts; therefore, MidAmerican Energy'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, MidAmerican Energy 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, related volatility, counterparty creditworthiness and duration of contracts.

December 31, 2020, respectively.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, and are primarilywith debt securities 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 and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 
Commodity
Derivatives
 
Auction Rate
Securities
 
Commodity
Derivatives
 Auction Rate Securities
2017:       
Beginning balance$(1) $—
 $(2) $—
Changes in fair value recognized in net regulatory assets(2) —
 (2) —
Settlements1
 —
 2
 —
Ending balance$(2) $—
 $(2) $—
        
2016:       
Beginning balance$(2) $18
 $(6) $26
Transfer to affiliate—
 —
 (4) —
Changes in fair value recognized in OCI—
 —
 —
 3
Changes in fair value recognized in net regulatory assets(1) —
 (5) —
Redemptions—
 —
 —
 (11)
Settlements1
 —
 13
 —
Ending balance$(2) $18
 $(2) $18


MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. 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 (in millions):
As of September 30, 2021As of December 31, 2020
Carrying
Value		Fair
Value		Carrying
Value		Fair
Value
Long-term debt$7,716 $9,101 $7,210 $9,130 

95
 As of September 30, 2017 As of December 31, 2016
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
        
Long-term debt$4,894
 $5,446
 $4,301
 $4,735


(8)(9)    Commitments and Contingencies


Natural GasConstruction Commitments


During the nine-month period ended September 30, 2017,2021, MidAmerican Energy amended certain of its natural gas supply and transportation contracts increasing minimum payments by $247entered into firm construction commitments totaling $405 million through the remainder of 2021 and $70 million for 2022 through 2037.related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.


Construction CommitmentsEasements


During the nine-month period ended September 30, 2017, MidAmerican Energy entered into contracts totaling $675 million for the construction of wind-powered generating facilities in 2017 through 2019, with remaining payments totaling $84 million for the fourth quarter of 2017, $340 million in 2018 and $8 million in 2019.

Easements

During the nine-month period ended September 30, 2017,2021, MidAmerican Energy entered into non-cancelable easements with minimum paymentspayment commitments totaling $114$87 million through 20572061 for land in Iowa on which some of its wind-poweredwind- and solar-powered generating facilities will be located.




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.


Environmental Laws and Regulations


MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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-approvedFederal Energy Regulatory Commission ("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 a 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 September 30, 2017,2021, has accrued a $9 million liability for refunds under the second complaint of amounts collected under the higher ROE during the periods covered by both complaints.

96

(10)    Revenue from February 2015 through May 2016.Contracts with Customers

(9)Components of Accumulated Other Comprehensive Income (Loss), Net


The following table shows the changesummarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in accumulated other comprehensive income (loss), net by each component of other comprehensive income, net of applicable income taxesNote 11 (in millions):
For the Three-Month Period Ended September 30, 2021For the Nine-Month Period Ended September 30, 2021
ElectricNatural GasOtherTotalElectricNatural GasOtherTotal
Customer Revenue:
Retail:
Residential$255 $52 $— $307 $586 $419 $— $1,005 
Commercial107 17 — 124 258 164 — 422 
Industrial321 5 — 326 741 20 — 761 
Natural gas transportation services— 9 — 9 — 28 — 28 
Other retail(1)
53 1 — 54 119 2 — 121 
Total retail736 84 — 820 1,704 633 — 2,337 
Wholesale88 25 — 113 214 93 — 307 
Multi-value transmission projects15 — — 15 45 — — 45 
Other Customer Revenue— — 2 2 — — 13 13 
Total Customer Revenue839 109 2 950 1,963 726 13 2,702 
Other revenue15 1 — 16 22 2 — 24 
Total operating revenue$854 $110 $2 $966 $1,985 $728 $13 $2,726 

For the Three-Month Period Ended September 30, 2020For the Nine-Month Period Ended September 30, 2020
ElectricNatural GasOtherTotalElectricNatural GasOtherTotal
Customer Revenue:
Retail:
Residential$241 $46 $— $287 $555 $233 $— $788 
Commercial99 13 — 112 242 71 — 313 
Industrial280 2 — 282 640 9 — 649 
Natural gas transportation services— 8 — 8 — 26 — 26 
Other retail(1)
42 1 — 43 103 2 — 105 
Total retail662 70 — 732 1,540 341 — 1,881 
Wholesale46 10 — 56 116 41 — 157 
Multi-value transmission projects14 — — 14 47 — — 47 
Other Customer Revenue— — 4 4 — — 5 5 
Total Customer Revenue722 80 4 806 1,703 382 5 2,090 
Other revenue6 — — 6 14 2 — 16 
Total operating revenue$728 $80 $4 $812 $1,717 $384 $5 $2,106 

(1)    Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.

97
  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 2
 —
 2
Dividend —
 27
 27
Balance at September 30, 2016 $(1) $—
 $(1)


(11)    Segment Information
(10)Segment Information


MidAmerican Energy has identified two2 reportable 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 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.




The following tables provide information on a reportable segment basis (in millions):
Three-Month PeriodsNine-Month Periods
 Ended September 30,Ended September 30,
2021202020212020
Operating revenue:
Regulated electric$854 $728 $1,985 $1,717 
Regulated natural gas110 80 728 384 
Other2 4 13 5 
Total operating revenue$966 $812 $2,726 $2,106 
Operating income:
Regulated electric$289 $238 $401 $398 
Regulated natural gas(2)(6)37 40 
Total operating income287 232 438 438 
Interest expense(76)(74)(224)(224)
Allowance for borrowed funds4 5 8 12 
Allowance for equity funds11 16 25 33 
Other, net8 14 34 30 
Income before income tax benefit$234 $193 $281 $289 

As of
September 30,
2021		December 31,
2020
Assets:
Regulated electric$21,063 $19,892 
Regulated natural gas1,874 1,544 
Other7 1 
Total assets$22,944 $21,437 


98
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Operating revenue:       
Regulated electric$707
 $692
 $1,677
 $1,572
Regulated gas103
 102
 485
 430
Other3
 1
 4
 2
Total operating revenue$813
 $795
 $2,166
 $2,004
        
Depreciation and amortization:       
Regulated electric$101
 $107
 $338
 $306
Regulated gas10
 11
 31
 32
Total depreciation and amortization$111
 $118
 $369
 $338
  
  
  
  
Operating income:       
Regulated electric$290
 $289
 $485
 $481
Regulated gas(2) (5) 45
 42
Total operating income$288
 $284
 $530
 $523


 As of
 September 30,
2017		 December 31,
2016
Assets:   
Regulated electric$15,556
 $14,113
Regulated gas1,339
 1,345
Other7
 1
Total assets$16,902
 $15,459








REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the Board of Managers and Member of
MidAmerican Funding, LLC
Des Moines, Iowa

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2017, and2021, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, and of changes in equity and cash flows for the nine-month periods ended September 30, 20172021 and 2016. These2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements areinformation for it to be in conformity with accounting principles generally accepted in the responsibilityUnited States of MidAmerican Funding's management.America.


We conducted our reviewshave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2020, and the related consolidated statements of operations, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States)PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.



/s/ Deloitte & Touche LLP




Des Moines, Iowa
November 3, 20175, 2021




99

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)


As of
September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$542 $39 
Trade receivables, net555 234 
Inventories244 278 
Other current assets143 74 
Total current assets1,484 625 
Property, plant and equipment, net19,774 19,279 
Goodwill1,270 1,270 
Regulatory assets479 392 
Investments and restricted investments977 913 
Other assets234 232 
Total assets$24,218 $22,711 
 As of
 September 30, December 31,
 2017 2016
ASSETS
Current assets:   
Cash and cash equivalents$512
 $15
Receivables, net318
 287
Income taxes receivable—
 9
Inventories235
 264
Other current assets21
 35
Total current assets1,086
 610
    
Property, plant and equipment, net13,602
 12,835
Goodwill1,270
 1,270
Regulatory assets1,335
 1,161
Investments and restricted cash and investments709
 655
Other assets194
 216
    
Total assets$18,196
 $16,747


The accompanying notes are an integral part of these consolidated financial statements.

100


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)


As of
September 30,December 31,
20212020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable$347 $408 
Accrued interest90 83 
Accrued property, income and other taxes242 161 
Note payable to affiliate190 177 
Other current liabilities226 183 
Total current liabilities1,095 1,012 
Long-term debt7,956 7,450 
Regulatory liabilities943 1,111 
Deferred income taxes3,405 3,052 
Asset retirement obligations677 709 
Other long-term liabilities495 458 
Total liabilities14,571 13,792 
Commitments and contingencies (Note 9)00
Member's equity:
Paid-in capital1,679 1,679 
Retained earnings7,968 7,240 
Total member's equity9,647 8,919 
Total liabilities and member's equity$24,218 $22,711 
 As of
 September 30, December 31,
 2017 2016
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:   
Accounts payable$256
 $302
Accrued interest54
 52
Accrued property, income and other taxes227
 138
Note payable to affiliate52
 31
Short-term debt—
 99
Current portion of long-term debt350
 250
Other current liabilities159
 160
Total current liabilities1,098
 1,032
    
Long-term debt4,870
 4,377
Deferred income taxes3,777
 3,568
Regulatory liabilities927
 883
Asset retirement obligations515
 510
Other long-term liabilities307
 291
Total liabilities11,494
 10,661
    
Commitments and contingencies (Note 8)
 
    
Member's equity:   
Paid-in capital1,679
 1,679
Retained earnings5,023
 4,407
Total member's equity6,702
 6,086
    
Total liabilities and member's equity$18,196
 $16,747


The accompanying notes are an integral part of these consolidated financial statements.




101

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)


Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Operating revenue:
Regulated electric$854 $728 $1,985 $1,717 
Regulated natural gas and other112 84 741 397 
Total operating revenue966 812 2,726 2,114 
Operating expenses:
Cost of fuel and energy163 115 417 266 
Cost of natural gas purchased for resale and other64 40 553 211 
Operations and maintenance200 212 577 560 
Depreciation and amortization218 180 634 531 
Property and other taxes34 33 107 102 
Total operating expenses679 580 2,288 1,670 
Operating income287 232 438 444 
Other income (expense):
Interest expense(81)(79)(237)(238)
Allowance for borrowed funds4 5 8 12 
Allowance for equity funds11 16 25 33 
Other, net8 15 34 30 
Total other income (expense)(58)(43)(170)(163)
Income before income tax benefit229 189 268 281 
Income tax benefit(144)(148)(460)(414)
Net income$373 $337 $728 $695 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Operating revenue:       
Regulated electric$707
 $692
 $1,677
 $1,572
Regulated gas and other108
 105
 493
 436
Total operating revenue815
 797
 2,170
 2,008
        
Operating costs and expenses:       
Cost of fuel, energy and capacity130
 130
 342
 312
Cost of gas sold and other54
 56
 289
 239
Operations and maintenance202
 181
 549
 511
Depreciation and amortization111
 118
 369
 338
Property and other taxes30
 28
 90
 84
Total operating costs and expenses527
 513
 1,639
 1,484
        
Operating income288
 284
 531
 524
        
Other income (expense):       
Interest expense(59) (55) (177) (164)
Allowance for borrowed funds4
 3
 9
 6
Allowance for equity funds11
 6
 25
 14
Other, net6
 3
 14
 9
Total other income (expense)(38) (43) (129) (135)
        
Income before income tax benefit250
 241
 402
 389
Income tax benefit(133) (77) (214) (129)
        
Net income$383
 $318
 $616
 $518


The accompanying notes are an integral part of these consolidated financial statements.




102

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)


Paid-in
Capital		Retained
Earnings		Total Member's
Equity
Balance, June 30, 2020$1,679 $6,780 $8,459 
Net income— 337 337 
Balance, September 30, 2020$1,679 $7,117 $8,796 
Balance, December 31, 2019$1,679 $6,422 $8,101 
Net income— 695 695 
Balance, September 30, 2020$1,679 $7,117 $8,796 
Balance, June 30, 2021$1,679 $7,594 $9,273 
Net income— 373 373 
Other equity transactions— 1 1 
Balance, September 30, 2021$1,679 $7,968 $9,647 
Balance, December 31, 2020$1,679 $7,240 $8,919 
Net income— 728 728 
Balance, September 30, 2021$1,679 $7,968 $9,647 
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, Net
 
Total
Equity
        
Balance, December 31, 2015$1,679
 $3,876
 $(30) $5,525
Net income—
 518
 —
 518
Other comprehensive income—
 —
 2
 2
Transfer to affiliate—
 —
 27
 27
Other equity transactions—
 (1) —
 (1)
Balance, September 30, 2016$1,679
 $4,393
 $(1) $6,071
        
Balance, December 31, 2016$1,679
 $4,407
 $—
 $6,086
Net income—
 616
 —
 616
Balance, September 30, 2017$1,679
 $5,023
 $—
 $6,702


The accompanying notes are an integral part of these consolidated financial statements.




103

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)


Nine-Month Periods
Ended September 30,
20212020
Cash flows from operating activities:
Net income$728 $695 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization634 531 
Amortization of utility plant to other operating expenses26 25 
Allowance for equity funds(25)(33)
Deferred income taxes and investment tax credits, net121 79 
Settlements of asset retirement obligations(51)(55)
Other, net42 (1)
Changes in other operating assets and liabilities:
Trade receivables and other assets(331)(16)
Inventories34 (40)
Pension and other postretirement benefit plans2 (17)
Accrued property, income and other taxes, net80 (13)
Accounts payable and other liabilities16 44 
Net cash flows from operating activities1,276 1,199 
Cash flows from investing activities:
Capital expenditures(1,266)(1,341)
Purchases of marketable securities(166)(251)
Proceeds from sales of marketable securities163 244 
Other, net(7)10 
Net cash flows from investing activities(1,276)(1,338)
Cash flows from financing activities:
Proceeds from long-term debt492 — 
Repayments of long-term debt(1)— 
Net change in note payable to affiliate13 13 
Other, net(1)(1)
Net cash flows from financing activities503 12 
Net change in cash and cash equivalents and restricted cash and cash equivalents503 (127)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period46 331 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$549 $204 
 Nine-Month Periods
 Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income$616
 $518
Adjustments to reconcile net income to net cash flows from operating activities:   
Depreciation and amortization369
 338
Deferred income taxes and amortization of investment tax credits64
 113
Changes in other assets and liabilities28
 34
Other, net(24) (42)
Changes in other operating assets and liabilities:   
Receivables, net(31) (67)
Inventories29
 (26)
Derivative collateral, net3
 4
Contributions to pension and other postretirement benefit plans, net(8) (5)
Accounts payable(4) 14
Accrued property, income and other taxes, net96
 160
Other current assets and liabilities14
 24
Net cash flows from operating activities1,152
 1,065
    
Cash flows from investing activities:   
Utility construction expenditures(1,162) (1,129)
Purchases of available-for-sale securities(126) (96)
Proceeds from sales of available-for-sale securities127
 92
Other, net(3) 5
Net cash flows from investing activities(1,164) (1,128)
    
Cash flows from financing activities:   
Proceeds from long-term debt842
 33
Repayments of long-term debt(255) (38)
Net change in note payable to affiliate21
 16
Net repayments of short-term debt(99) —
Net cash flows from financing activities509
 11
    
Net change in cash and cash equivalents497
 (52)
Cash and cash equivalents at beginning of period15
 103
Cash and cash equivalents at end of period$512
 $51


The accompanying notes are an integral part of these consolidated financial statements.




104

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(1)General

(1)    General

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. and MEC Construction Services Co.


The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2017,2021, and for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2021 and 2020. The results of operations for the three- and nine-month periods ended September 30, 2017,2021, are not necessarily indicative of the results to be expected for the full year.


The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2016,2020, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2017.2021.


(2)New Accounting Pronouncements

Refer to Note 2(2)    Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of MidAmerican Energy's Notes to Financial Statements.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 September 30, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 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
September 30,December 31,
20212020
Cash and cash equivalents$542 $39 
Restricted cash and cash equivalents in other current assets7 7 
Total cash and cash equivalents and restricted cash and cash equivalents$549 $46 

(3)Property, Plant and Equipment, Net

105

(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 as of September 30, 2017 and December 31, 2016, nonregulated property gross of $25 million and $22 million, respectively, related accumulated depreciation and amortization of $10 million and $9 million, respectively, and construction work-in-progress of $- million and $1 million, respectively, which consisted primarily of a corporate aircraft owned by MHC.


(4)    Recent Financing TransactionsRegulatory Matters


Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.


(5)    Recent Financing Transactions



Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
(5)Income Taxes


(6)    Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(45)(56)(150)(126)
State income tax, net of federal income tax impacts(27)(27)(29)(30)
Effects of ratemaking(12)(16)(14)(13)
Other, net— — — 1 
Effective income tax rate(63)%(78)%(172)%(147)%
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Federal statutory income tax rate35 % 35 % 35 % 35 %
Income tax credits(76) (60) (76) (61)
State income tax, net of federal income tax benefit(10) (7) (8) (4)
Effects of ratemaking(2) —
 (4) (3)
Effective income tax rate(53)% (32)% (53)% (33)%


Income tax credits relate primarily to production tax credits ("PTCs") from 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. MidAmerican Funding recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. 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 three-month periods ended September 30, 2021 and 2020 totaled $103 million and $105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352 million, respectively.


Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax return.returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income taxestax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income taxes aretax is remitted to or received from BHE. The timing of MidAmerican Funding's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. MidAmerican Funding received net cash payments for income taxestax from BHE totaling $386$681 million and $422$504 million for the nine-month periods ended September 30, 20172021 and 2016,2020, respectively.


(6)Employee Benefit Plans

(7)    Employee Benefit Plans

Refer to Note 67 of MidAmerican Energy's Notes to Financial Statements.


106
(7)Fair Value Measurements


(8)    Fair Value Measurements

Refer to Note 78 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 (in millions):
As of September 30, 2021As of December 31, 2020
Carrying
Value		Fair
Value		Carrying
Value		Fair
Value
Long-term debt$7,956 $9,417 $7,450 $9,466 

 As of September 30, 2017 As of December 31, 2016
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
        
Long-term debt$5,220
 $5,873
 $4,627
 $5,164

(8)(9)    Commitments and Contingencies


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.

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.

(9)    Components of Accumulated Other Comprehensive Income (Loss), Net


Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.




(10)    Revenue from Contracts with Customers

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million for the three-month periods ended September 30, 2021 and 2020, respectively, and $— million and $8 million for the nine-month periods ended September 30, 2021 and 2020, respectively.

107

(11)    Segment Information


MidAmerican Funding has identified two2 reportable 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 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 financial results and assets of nonregulated operations, MHC and MidAmerican Funding.


The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods Nine-Month PeriodsThree-Month PeriodsNine-Month Periods
Ended September 30, Ended September 30,Ended September 30,Ended September 30,
2017 2016 2017 20162021202020212020
Operating revenue:       Operating revenue:
Regulated electric$707
 $692
 $1,677
 $1,572
Regulated electric$854 $728 $1,985 $1,717 
Regulated gas103
 102
 485
 430
Regulated natural gasRegulated natural gas110 80 728 384 
Other5
 3
 8
 6
Other2 4 13 13 
Total operating revenue$815
 $797
 $2,170
 $2,008
Total operating revenue$966 $812 $2,726 $2,114 
       
Depreciation and amortization:       
Regulated electric$101
 $107
 $338
 $306
Regulated gas10
 11
 31
 32
Total depreciation and amortization$111
 $118
 $369
 $338
       
Operating income:       Operating income:
Regulated electric$290
 $289
 $485
 $481
Regulated electric$289 $238 $401 $398 
Regulated gas(2) (5) 45
 42
Regulated natural gasRegulated natural gas(2)(6)37 40 
Other—
 —
 1
 1
Other— — — 6 
Total operating income$288
 $284
 $531
 $524
Total operating income287 232 438 444 
Interest expenseInterest expense(81)(79)(237)(238)
Allowance for borrowed fundsAllowance for borrowed funds4 5 8 12 
Allowance for equity fundsAllowance for equity funds11 16 25 33 
Other, netOther, net8 15 34 30 
Income before income tax benefitIncome before income tax benefit$229 $189 $268 $281 
 As of
 September 30,
2017		 December 31,
2016
Assets(1):
   
Regulated electric$16,747
 $15,304
Regulated gas1,418
 1,424
Other31
 19
Total assets$18,196
 $16,747

As of
September 30,
2021		December 31,
2020
Assets(1):
Regulated electric$22,254 $21,083 
Regulated natural gas1,953 1,623 
Other11 5 
Total assets$24,218 $22,711 
(1)Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.




108
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations

MidAmerican Funding is an Iowa limited liability company whose sole member is BHE. MidAmerican Funding owns all

Item 2.Management's Discussion and Analysis of the outstanding common stockFinancial Condition and Results of MHC Inc., which owns all of the common stock of MidAmerican Energy, Midwest Capital Group, Inc. and MEC Construction Services Co. MidAmerican Energy is a public utility company headquartered in Des Moines, Iowa. MHC Inc., MidAmerican Funding and BHE are also headquartered in Des Moines, Iowa.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 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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Energy'sFunding's and MidAmerican Funding'sEnergy's actual results in the future could differ significantly from the historical results.


Results of Operations for the Third Quarter and First Nine Months of 20172021 and 20162020


Overview


MidAmerican Energy -


MidAmerican Energy's net income for the third quarter of 20172021 was $385$377 million, an increase of $65$37 million, or 20%11%, compared to 20162020 primarily due to higher recognized production tax creditselectric utility margin of $45$78 million, higher margins of $11 million, excluding the impact of demand side management program revenue (offset inlower operations and maintenance expense), lower depreciation and amortizationexpenses of $7$12 million substantially from changesdue to storm restoration costs in accruals for Iowa regulatory arrangements,2020 and higher allowance for borrowed and equity fundsnatural gas utility margin of $6 million, partially offset by higher operationsdepreciation and maintenance expenses,amortization expense of $38 million, lower allowance for equity funds used during construction of $5 million due to lower construction work-in-progress balances, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and lower income tax benefit due to higher pretax income. Electric utility margin increased due to higher wholesale utility margin primarily reflecting higher market prices and higher retail utility margin mainly from higher generating facility maintenance, includingvolumes. Depreciation and amortization expense increased due to additional wind turbines. The increase in electric margins of $7 million, excludingassets placed in-service and the impact of demand side management program revenue (offset in operations and maintenance expense), reflects higher recoveries through bill riders, higher transmission revenue and higher retail customer volumes from industrial growth net of lower residential and commercial volumes due to milder temperatures, partially offset by lower wholesale revenue from lower sales volumes and prices.regulatory mechanisms.


MidAmerican Energy's net income for the first nine months of 20172021 was $624$737 million, an increase of $97$37 million, or 18%5%, compared to 20162020, primarily due to higher marginselectric utility margin of $64$117 million, excludinga favorable income tax benefit of $45 million and favorable changes in the impactcash surrender value of demand side management program revenuecorporate-owned life insurance policies, partially offset by higher depreciation and amortization expense of $103 million, higher operations and maintenance expenses, including increased costs associated with additional wind-powered generating facilities placed in-service and higher natural gas distribution costs, partially offset by lower electric distribution costs due to storm restoration costs in 2020 and lower allowances for equity and borrowed funds of $12 million. Electric utility margin increased due to higher retail utility margin, primarily from higher volumes and higher recoveries through bill riders (offset in operations and maintenance expense), higher recognized productionand income tax credits of $71 millionbenefit), and higher allowance for borrowed and equity funds of $14 million, partially offset by higher operations and maintenance expenses of $21 million, primarilywholesale utility margin from higher maintenancewholesale volumes. The favorable income tax benefit was due to higher PTCs recognized from additionalhigher wind-powered generation, driven primarily by new wind turbines, and higher depreciationprojects placed in-service. Depreciation and amortization of $31 million from accruals for Iowa regulatory arrangements and wind-powered generating facilitiesexpense increased due to additional assets placed in-service in the second half of 2016, net of a reduction in depreciation rates in December 2016. The increase in electric margins of $60 million, excludingand the impact of demand side management program revenue (offsetregulatory mechanisms.

On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by the IUB in operationsMidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense for the third quarter and maintenance expense), reflects higher recoveriesfirst nine months of 2021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower in years 2021 through bill riders, higher wholesale revenue from higher sales volumes and prices, higher transmission revenue and higher retail customer volumes from industrial growth, net2023 than would have been recognized absent the order. The annual amount of lower residential and commercial volumes due to milder temperatures, partially offset by higher coal-fueled generation and purchased power costs.the deferral for 2021 will be recognized in the fourth quarter.


MidAmerican Funding -


MidAmerican Funding's net income for the third quarter of 20172021 was $383$373 million, an increase of $65$36 million, or 20%11%, compared to 2016.2020. MidAmerican Funding's net income for the first nine months of 20172021 was $616$728 million, an increase of $98$33 million, or 19%5%, compared to 2016.The increases2020. The variances in net income were primarily due to the changes in MidAmerican Energy's earnings discussed above.



109


Non-GAAP Financial Measure
Regulated
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 Grossutility 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 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 expense 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 explain 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 comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
Third QuarterFirst Nine Months
20212020Change20212020Change
Electric utility margin:
Operating revenue$854 $728 $126 17 %$1,985 $1,717 $268 16 %
Cost of fuel and energy163 115 48 42 417 266 151 57 
Electric utility margin691 613 78 13 %1,568 1,451 117 8 %
Natural gas utility margin:
Operating revenue110 80 30 38 %728 384 344 *
Natural gas purchased for resale63 39 24 62 552 209 343 *
Natural gas utility margin47 41 6 15 %176 175 1 1 %
Utility margin738 654 84 13 %1,744 1,626 118 7 %
Other operating revenue2 4 (2)(50)%13 5 8 *
Other cost of sales1 1 — — 1 1 — *
Operations and maintenance200 212 (12)(6)577 559 18 3 
Depreciation and amortization218 180 38 21 634 531 103 19 
Property and other taxes34 33 1 3 107 102 5 5 
Operating income$287 $232 $55 24 %$438 $438 $— — %

*    Not meaningful.

110

Electric Utility Margin


A comparison of key operating results related to regulated electric grossutility margin is as follows:
Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$854 $728 $126 17 %$1,985 $1,717 $268 16 %
Cost of fuel and energy163 115 48 42 417 266 151 57 
Utility margin$691 $613 $78 13 %$1,568 $1,451 $117 8 %
Sales (GWhs):
Residential2,060 2,053 7 — %5,284 5,226 58 1 %
Commercial1,039 1,013 26 3 2,871 2,800 71 3 
Industrial4,106 3,758 348 9 11,981 10,884 1,097 10 
Other423 398 25 6 1,194 1,117 77 7 
Total retail7,628 7,222 406 6 21,330 20,027 1,303 7 
Wholesale3,420 2,541 879 35 11,343 7,535 3,808 51 
Total sales11,048 9,763 1,285 13 %32,673 27,562 5,111 19 %
Average number of retail customers (in thousands)8057969 1 %8037949 1 %
Average revenue per MWh:
Retail$96.42 $91.62 $4.80 5 %$79.90 $76.92 $2.98 4 %
Wholesale$27.07 $17.34 $9.73 56 %$18.22 $14.54 $3.68 25 %
Heating degree days21 96 (75)(78)%3,820 3,698 122 3 %
Cooling degree days870 795 75 9 %1,296 1,155 141 12 %
Sources of energy (GWhs)(1):
Wind and other(2)
4,164 4,274 (110)(3)%16,163 14,268 1,895 13 %
Coal4,609 3,169 1,440 45 10,302 5,771 4,531 79 
Nuclear1,007 1,000 7 1 2,911 2,902 9 — 
Natural gas503 324 179 55 982 517 465 90 
Total energy generated10,283 8,767 1,516 17 30,358 23,458 6,900 29 
Energy purchased1,038 1,166 (128)(11)2,898 4,592 (1,694)(37)
Total11,321 9,933 1,388 14 %33,256 28,050 5,206 19 %
Average cost of energy per MWh:
Energy generated(3)
$9.81 $7.34 $2.47 34 %$7.48 $5.53 $1.95 35 %
Energy purchased$60.32 $43.32 $17.00 39 %$65.60 $29.67 $35.93 *

*    Not meaningful.

(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.
111

 Third Quarter First Nine Months
 2017 2016 Change 2017 2016 Change
Gross margin (in millions):               
Operating revenue$707
 $692
 $15
 2 % $1,677
 $1,572
 $105
 7 %
Cost of fuel, energy and capacity130
 130
 —
 —
 342
 312
 30
 10
Gross margin$577
 $562
 $15
 3
 $1,335
 $1,260
 $75
 6
                
Electricity Sales (GWh):               
Residential1,790
 1,969
 (179) (9)% 4,753
 5,018
 (265) (5)%
Commercial987
 1,023
 (36) (4) 2,796
 2,859
 (63) (2)
Industrial3,366
 3,106
 260
 8
 9,621
 8,999
 622
 7
Other411
 427
 (16) (4) 1,185
 1,213
 (28) (2)
Total retail6,554
 6,525
 29
 —
 18,355
 18,089
 266
 1
Wholesale1,571
 2,037
 (466) (23) 7,162
 5,620
 1,542
 27
Total sales8,125
 8,562
 (437) (5) 25,517
 23,709
 1,808
 8
                
Average number of retail customers (in thousands)771
 761
 10
 1 % 769
 759
 10
 1 %
                
Average revenue per MWh:               
Retail$98.15
 $94.02
 $4.13
 4 % $78.62
 $76.75
 $1.87
 2 %
Wholesale$25.57
 $28.13
 $(2.56) (9)% $23.90
 $22.84
 $1.06
 5 %
                
Heating degree days44
 27
 17
 63 % 3,203
 3,388
 (185) (5)%
Cooling degree days752
 855
 (103) (12)% 1,098
 1,284
 (186) (14)%
                
Sources of energy (GWh)(1):
               
Coal4,354
 4,618
 (264) (6)% 11,019
 9,907
 1,112
 11 %
Nuclear961
 1,003
 (42) (4) 2,820
 2,887
 (67) (2)
Natural gas257
 307
 (50) (16) 274
 515
 (241) (47)
Wind and other(2)
1,929
 1,950
 (21) (1) 9,129
 7,981
 1,148
 14
Total energy generated7,501
 7,878
 (377) (5) 23,242
 21,290
 1,952
 9
Energy purchased812
 916
 (104) (11) 2,756
 3,030
 (274) (9)
Total8,313
 8,794
 (481) (5) 25,998
 24,320
 1,678
 7
Natural Gas Utility Margin

(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 or other environmental commodities.


Regulated electric gross margin increased $15 million for the third quarter of 2017 compared to 2016 primarily due to:
(1)Higher retail gross margin of $16 million due to -
an increase of $38 million from higher recoveries through bill riders;
an increase of $3 million from non-weather-related usage factors, including higher industrial sales volumes;
a decrease of $12 million from the impact of milder temperatures; and
a decrease of $13 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs;
(2)Higher Multi-Value Projects ("MVPs") transmission revenue of $6 million due to continued capital additions; and
(3)Lower wholesale gross margin of $7 million due to lower margins per unit from lower market prices and lower sales volumes.

Regulated electric gross margin increased $75 million for the first nine months of 2017 compared to 2016 primarily due to:
(1)Higher wholesale gross margin of $37 million primarily due to higher margins per unit from higher market prices and higher sales volumes enabled by greater availability of lower cost generation;
(2)Higher retail gross margin of $25 million due to -
an increase of $47 million from higher recoveries through bill riders;
an increase of $28 million from non-weather-related usage factors, including higher industrial sales volumes;
a decrease of $25 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs; and
a decrease of $25 million from the impact of milder temperatures; and
(3)Higher MVPs transmission revenue of $11 million due to continued capital additions.



Regulated Gas Gross Margin
A comparison of key operating results related to regulatednatural gas grossutility margin is as follows:
Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$110 $80 $30 38  %$728 $384 $344 90  %
Natural gas purchased for resale63 39 24 62 552 209 343 *
Utility margin$47 $41 $6 15  %$176 $175 $1 1  %
Throughput (000's Dths):
Residential2,689 3,190 (501)(16)%34,243 34,146 97 —  %
Commercial1,511 1,671 (160)(10)16,255 15,634 621 4 
Industrial1,110 1,105 5 — 3,616 3,687 (71)(2)
Other4 6 (2)(33)52 54 (2)(4)
Total retail sales5,314 5,972 (658)(11)54,166 53,521 645 1 
Wholesale sales6,365 5,622 743 13 22,955 24,391 (1,436)(6)
Total sales11,679 11,594 85 1 77,121 77,912 (791)(1)
Natural gas transportation service26,789 24,973 1,816 7 83,282 82,092 1,190 1 
Total throughput38,468 36,567 1,901 5  %160,403 160,004 399 —  %
Average number of retail customers (in thousands)776 769 7 1 %776 770 6 1 %
Average revenue per retail Dth sold$14.21 $10.43 $3.78 36  %$11.20 $5.91 $5.29 90  %
Heating degree days28 122 (94)(77) %3,954 3,899 55 1  %
Average cost of natural gas per retail Dth sold$7.09 $4.74 $2.35 50  %$8.47 $3.12 $5.35 *
Combined retail and wholesale average cost of natural gas per Dth sold$5.42 $3.32 $2.10 63  %$7.16 $2.68 $4.48 *
 Third Quarter First Nine Months
 2017 2016 Change 2017 2016 Change
Gross margin (in millions):               
Operating revenue$103
 $102
 $1
 1 % $485
 $430
 $55
 13 %
Cost of gas sold54
 54
 —
 —
 288
 236
 52
 22
Gross margin$49
 $48
 $1
 2
 $197
 $194
 $3
 2
                
Natural gas throughput (000's Dth):               
Residential2,773
 2,820
 (47) (2) % 29,442
 31,121
 (1,679) (5) %
Commercial1,788
 1,840
 (52) (3) 14,797
 15,729
 (932) (6)
Industrial717
 922
 (205) (22) 3,070
 3,574
 (504) (14)
Other2
 1
 1
 100
 29
 26
 3
 12
Total retail sales5,280
 5,583
 (303) (5) 47,338
 50,450
 (3,112) (6)
Wholesale sales8,815
 8,568
 247
 3
 29,111
 28,615
 496
 2
Total sales14,095
 14,151
 (56) —
 76,449
 79,065
 (2,616) (3)
Gas transportation service19,784
 18,087
 1,697
 9
 65,431
 60,117
 5,314
 9
Total gas throughput33,879
 32,238
 1,641
 5
 141,880
 139,182
 2,698
 2
                
Average number of retail customers (in thousands)746
 738
 8
 1 % 747
 738
 9
 1 %
Average revenue per retail Dth sold$13.33
 $12.77
 $0.56
 4 % $7.93
 $6.80
 $1.13
 17 %
Average cost of natural gas per retail Dth sold$5.56
 $5.49
 $0.07
 1 % $4.33
 $3.45
 $0.88
 26 %
                
Combined retail and wholesale average cost of natural gas per Dth sold$3.82
 $3.82
 $—
 — % $3.76
 $2.99
 $0.77
 26 %
                
Heating degree days45
 27
 18
 67 % 3,406
 3,572
 (166) (5) %


*    Not meaningful.
Regulated gas revenue includes purchased gas adjustment clauses through which
Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020

MidAmerican Energy is allowed to recover the cost of gas sold from its retail gas-

Electric utility customers. Consequently, fluctuations in the cost of gas sold do not directly affect gross margin increased $78 million, or net income because regulated gas revenue reflects comparable fluctuations through the purchased gas adjustment clauses. For the first nine months of 2017, MidAmerican Energy's combined retail and wholesale average per-unit cost of gas sold increased 26%13%, resulting in an increase of $59 million in gas revenue and cost of gas sold compared to 2016, partially offset by lower gas sales volumes.

Regulated gas gross margin increased $1 million for the third quarter of 20172021 compared to 20162020, primarily due to:
•a $41 million increase in wholesale utility margin due to higher margin per unit of $35 million, reflecting higher market prices, and higher volumes of 34.6%; and
•a $36 million increase in retail utility margin primarily due to $20 million from higher usage for certain industrial customers; $6 million from liquidated damages related to a wind-powered generation project; $5 million, net of energy costs, from higher recoveries of demand side management program revenuethrough bill riders (offset in operations and maintenance expense)expense and income tax benefit); and $4 million from the favorable impact of weather. Retail customer volumes increased 5.6%.

RegulatedNatural gas grossutility margin increased $3$6 million, for the first nine months of 2017 compared to 2016 primarily due to -
(1)higher recoveries of demand side management program revenue (offset in operations and maintenance expense) of $2 million;
(2)a higher average per-unit margin of $2 million;
(3)higher gas transportation throughput of $1 million, and
(4)lower retail sales volumes of $3 million from warmer winter temperatures.



Operating Costs and Expenses

MidAmerican Energy -

Operations and maintenance increased $20 millionor 15%, for the third quarter of 20172021 compared to 20162020 primarily due to:
•an $8 million increase from higher average prices primarily due to higher demand side management program expense (offset in operating revenue)the timing of $8recoveries through a capital tracker mechanism; partially offset by
•a $3 million higher wind-powered generation maintenancedecrease from additional wind turbinesthe unfavorable impact of $6 million and higher coal-fueled and nuclear generation maintenance of $4 million.weather.

112

Operations and maintenance increased $37decreased $12 million, for the first nine months of 2017 compared to 2016 primarily due to higher demand side management program expense (offset in operating revenue) of $17 million, higher wind-powered generation maintenance from additional wind turbines of $13 million and higher coal-fueled and nuclear generation maintenance of $4 million.

Depreciation and amortization decreased $7 millionor 6%, for the third quarter of 20172021 compared to 20162020 primarily due to lower accrualselectric distribution maintenance costs of $21 million due to storm restoration costs in 2020, partially offset by higher other generation operations expenses of $4 million due to additional wind turbines and easements and higher transmission operations costs from MISO of $3 million.

Depreciation and amortization for Iowathe third quarter of 2021 increased $38 million, or 21%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service, $13 million from a regulatory arrangements of $9 millionmechanism deferring certain depreciation expense in 2020 and $9 million from lowera regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above for a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation rates implemented in December 2016, partially offset by utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016.expense.


Depreciation and amortization increased $31 million for the first nine months of 2017 compared to 2016 due to utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016, accruals for Iowa regulatory arrangements of $26 million, partially offset by $26 million from lower depreciation rates implemented in December 2016.

Property and other taxes increased $2 million and $6 million for the third quarter and first nine months of 2017 compared to 2016 primarily due to higher Iowa utility property replacement taxes.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $4 million and $13 million for the third quarter and first nine months of 2017, respectively, compared to 2016 due to higher interest expense from the issuance of $850 million of first mortgage bonds in February 2017, partially offset by the redemption of a $250 million of 5.95% Senior Notes in February 2017.

Allowance for borrowed and equity funds increased decreased $6 million, and $14 millionor 29%, for the third quarter and first nine months of 2017, respectively,2021 compared to 20162020 primarily due to higherlower construction work-in-progress balances related to wind-powered generation.


Other, net increased $2 decreased $6 million, and $5 million for the third quarter and first nine months of 2017, respectively, compared to 2016 primarily due to higher returns on corporate-owned life insurance policies.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit increased $57 millionor 43%, for the third quarter of 20172021 compared to 2016,2020 primarily due to lower cash surrender values of corporate-owned life insurance policies.

Income tax benefit decreased $4 million, or 3%, for the third quarter of 2021 compared to 2020, and the effective tax rate was (52)(61)% for 20172021 and (30)(76)% for 2016. For the first nine months of 2017 compared to 2016, MidAmerican Energy's income tax benefit increased $84 million, and the effective tax rate was (50)% for 2017 and (30)% for 2016.2020. The changeschange in the effective tax rates for 20172021 compared to 2016 were substantially2020 was primarily due to an increase in recognized production tax credits and the effects of ratemaking.a higher pretax income.


Production tax credits are recognized in earnings for interim periods based on the application of an estimated annual effective tax rate to pretax earnings. 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, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities wereare placed in service. Production tax credits recognized in the first nine months of 2017 were $306 million, or $71 million higher than the first nine months of 2016, while production tax credits earned in the first nine months of 2017 were $200 million, or $29 million higher than the first nine months of 2016 primarily due to wind-powered generation placed in-service in late 2016. The excess of production tax credits recognized over earned of $106 million as of September 30, 2017, will reduce earnings over the remainder of 2017.



MidAmerican Funding -

MidAmerican Funding's income tax benefit increased $56 millionin-service. PTCs for the third quarter of 20172021 and 2020 totaled $103 million and $105 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $4 million, or 3%, for the third quarter of 2021 compared to 2016,2020, and the effective tax rate was (53)(63)% for 20172021 and (32)(78)% for 2016.2020. The changes in the effective tax rates were due to the factors discussed for MidAmerican Funding's income tax benefitEnergy.

First Nine Months of 2021 compared to First Nine Months of 2020

MidAmerican Energy -

Electric utility margin increased $85$117 million, or 8%, for the first nine months of 20172021 compared to 2016,2020, due to:
•a $90 million increase in retail utility margin primarily due to $42 million from higher usage for certain industrial customers; $17 million from the favorable impact of weather; $17 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $7 million due to price impacts from changes in sales mix and $6 million from liquidated damages related to a wind-powered generation project. Retail customer volumes increased 6.5%; and
•a $29 million increase in wholesale utility margin due to higher volumes of 50.5%, partially offset by lower margins per unit of $10 million, reflecting higher energy costs; partially offset by
•a $2 million decrease in Multi-Value Projects transmission revenue.
Natural gas utility margin increased $1 million, or 1%, for the first nine months of 2021 compared to 2020 primarily due to:
•a $5 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•a $2 million increase natural gas transportation margin, reflecting higher volumes; partially offset by
•a $7 million decrease from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit).

113

Operations and maintenance increased $18 million, or 3%, for the first nine months of 2021 compared to 2020 primarily due to higher other generation operations and maintenance expenses of $12 million due to additional wind turbines and easements, higher energy efficiency program expense of $9 million (offset in operating revenue), higher natural gas distribution costs of $6 million and higher transmission operations costs from MISO of $3 million, partially offset by lower electric distribution costs of $15 million due to storm restoration costs in 2020.

Depreciation and amortization for the first nine months of 2021 increased $103 million, or 19%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $39 million from a regulatory mechanism deferring certain depreciation expense in 2020 and $18 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above for a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation expense.

Allowance for borrowed and equity funds decreased $12 million, or 27%, for the first nine months of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $4 million, or 13%, for the first nine months of 2021 compared to 2020 primarily due to higher cash surrender values of corporate-owned life insurance policies, partially offset by higher non-service costs of postretirement employee benefit plans.

Income tax benefit increased $45 million, or 11%, for the first nine months of 2021 compared to 2020, and the effective tax rate was (53)(162)% for 20172021 and (33)(142)% for 2016.The2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income. PTCs for the first nine months of 2021 and 2020 totaled $400 million and $352 million, respectively.

MidAmerican Funding -

Income tax benefit increased $46 million, or 11%, for the first nine months of 2021 compared to 2020, and the effective tax rate was (172)% for 2021 and (147)% for 2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.


114

Liquidity and Capital Resources


As of September 30, 2017, MidAmerican Energy's2021, the total net liquidity for MidAmerican Energy and MidAmerican Funding was $1,197 million consisting of $512 million of cash and cash equivalents and $905 million of credit facilities reduced by $220 million of the credit facilities reserved to support MidAmerican Energy's variable-rate tax-exempt bond obligations. As of September 30, 2017, MidAmerican Funding's total net liquidity was $1,201 million, including MHC Inc.'s $4 million credit facility.as follows (in millions):


MidAmerican Energy:
Cash and cash equivalents$541 
Credit facilities, maturing 2022 and 20241,505 
Less:
Tax-exempt bond support(370)
Net credit facilities1,135 
MidAmerican Energy total net liquidity$1,676 
MidAmerican Funding:
MidAmerican Energy total net liquidity$1,676 
Cash and cash equivalents1 
MHC, Inc. credit facility, maturing 20224 
MidAmerican Funding total net liquidity$1,681 

Operating Activities


MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 20172021 and 2016,2020, were $1,171$1,290 million and $1,080$1,209 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 20172021 and 2016,2020, were $1,152$1,276 million and $1,065$1,199 million, respectively. Cash flows from operating activities increased primarily due toreflect higher income tax receipts and lower payments for the settlement of asset retirement obligations, partially offset by lower cash gross margins for MidAmerican Energy's regulated electric business,and natural gas businesses, including fuel inventory reductions, partially offset bydelayed recovery of higher natural gas costs in February 2021, discussed below, and higher payments to vendors.

In February 2021, severe cold weather over the timingcentral 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 income tax cash flows with BHE.retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to MidAmerican Energy's income tax cash flows with BHE totaled net cash receipts from BHEcustomers, the IUB ordered the recovery of $381 millionthese higher costs to be applied to customer bills over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and $416 million, respectively. Income tax cash flows for 2016 reflectlonger recovery period resulted in higher working capital requirements during the receipt of $106 million of income tax benefits generated in 2015. nine-month period ended September 30, 2021.

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 and assumptions for each payment date.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Production tax credits were extended and phased-out for wind power and other forms of non-solar renewable energy projects that begin construction before the end of 2019. Production tax credits are maintained at the following levels for projects for which construction begins before the end of the respective year as follows: at full value for 2016, at 80% of value for 2017, at 60% of value for 2018, and 40% of value for 2019. As a result of PATH, MidAmerican Energy's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in service through 2019 and production tax credits earned on qualifying wind projects through 2029.


Investing Activities


MidAmerican Energy's net cash flows from investing activities for the nine-month periods ended September 30, 20172021 and 2016,2020, were $(1,161)$(1,276) million and $(1,128)$(1,339) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 20172021 and 2016,2020, were $(1,164)$(1,276) million and $(1,128)$(1,338) million, respectively. Net cash flows from investing activities consist almost entirely of utility constructioncapital expenditures, which increaseddecreased primarily due to higher environmental and other operatinglower wind-powered generating facility construction expenditures. Purchases and proceeds related to available-for-salemarketable securities primarilysubstantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust.trust and other trust investments. Other, net for 2020 reflects $9 million of proceeds from corporate-owned life insurance policies.



115

Financing Activities


MidAmerican Energy's net cash flows from financing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $488$489 million and $(5)$(1) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 20172021 and 2016,2020, were $509$503 million and $11$12 million, respectively. In February 2017,Proceeds from long-term debt reflect MidAmerican Energy issued $375Energy's issuance in July 2021 of $500 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. An amount equal to the net proceeds was used to finance capital expenditures disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds. In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017. In January 2016, MidAmerican Energy repaid $4 million of variable-rate tax-exempt pollution control refunding revenue bonds due January 2016. Through its commercial paper program, MidAmerican Energy made payments totaling $99 million in 2017.2052. MidAmerican Funding received $21 million and $16$13 million in 20172021 and 2016,2020, respectively, through its note payable with BHE.




Debt Authorizations and Related Matters


MidAmerican Energy has authority from the FERC to issue, through February 28, 2019,April 2, 2022, commercial paper and bank notes aggregating $905 million$1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of up to 400 basis points. MidAmerican Energy has a $900 million$1.5 billion unsecured credit facility expiring in June 2020. MidAmerican Energy may request that the banks extend the credit facility up to two years.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.


MidAmerican Energy currently has an effective automatic registration statement with the United States Securities and Exchange CommissionSEC to issue an indeterminate amount of long-term debt securities through September 16, 2018.June 13, 2024. Additionally, following the July 2021 issuance of $500 million of first mortgage bonds, 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 Illinois Commerce Commission to issue long-term debt securities up to an aggregate of $2.4 billion at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points. Additionally, MidAmerican Energy has authorization from the Illinois Commerce Commission to issue preferred stock up to an aggregate of $500$350 million through November 1, 2020 and additional long-term debt securities up to an aggregate of $2.4 billion of additional long-term debt securities, of which $350 million expires March 15, 2018, $150 million expires September 22, 2018, $500 million expires March 15, 2019 and $1.4 billion expires November 1, 2020.August 20, 2022.

In conjunction with the March 1999 merger, 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 of 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. If MidAmerican Energy's common equity level were to drop below the required thresholds, MidAmerican Energy's ability to issue debt could be restricted. As of September 30, 2017, MidAmerican Energy's common equity ratio was 53% computed on a basis consistent with its commitment.


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 regulatory approvals, their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.


Utility ConstructionCapital Expenditures


MidAmerican Energy's primary need forEnergy has significant future capital is utility construction expenditures.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; 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.




MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Wind generation$713 $605 $807 
Electric distribution189 154 260 
Electric transmission132 105 194 
Solar generation2 97 180 
Other305 305 502 
Total$1,341 $1,266 $1,943 

116

 Nine-Month Periods Annual
 Ended September 30, Forecast
 2016 2017 2017
      
Wind-powered generation$732
 $455
 $709
Wind-powered generation repowering—
 272
 496
Transmission Multi-Value Projects73
 18
 25
Other324
 417
 773
Total$1,129
 $1,162
 $2,003

MidAmerican Energy's forecast utilitycapital expenditures provided above consist of the following:

•Wind generation includes the construction, expendituresacquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction and acquisition of wind-powered generating facilities totaled $275 million and $676 million for 2017 include the following:

Thenine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the construction of 2,000 MW (nominal ratings)additional wind-powered generating facilities totals $73 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2017 through 2019. In August 2016,2021.
◦Repowering of wind-powered generating facilities totaled $274 million and $25 million for the IUB issued an order approving ratemaking principles relatednine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the repowering of wind-powered generating facilities totals $101 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service 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 892 MWs of current repowering projects not in-service as of September 30, 2021, 591 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.
•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 reflects MidAmerican Energy's current plan for the construction of up to 2,000 MW (nominal ratings)141 MWs of additional wind-powered generating facilitiessmall- and utility-scale solar generation during 2021, of which 61 MWs are expected to be placed in-service in service in 2017 through 2019. The ratemaking principles establish 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. The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Additionally, the ratemaking principles modify the revenue sharing mechanism currently in effect. The revised sharing mechanism will be effective in 2018 and will be triggered each year by actual equity returns above the weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. Each of these projects is expected to qualify for 100% of production tax credits currently available.2021.
The repowering of certain existing wind-powered generating facilities in Iowa. This project entails the replacement of significant components of the oldest turbines in MidAmerican Energy’s fleet. The energy production from such repowered facilities is expected to qualify for 100% of the federal production tax credits available for ten years following completion. 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 excludes from MidAmerican Energy's Iowa energy adjustment clause any future federal production tax credits related to these repowered facilities.
Transmission MVP investments. MidAmerican Energy has approval from the Midcontinent Independent System Operator, Inc. for the construction of four MVPs located in Iowa and Illinois, which, when complete, will have added approximately 250 miles of 345 kV transmission line to MidAmerican Energy's transmission system since 2012.
•Remaining costs expenditures primarily relate to routine expenditures for other generation, transmission,natural gas distribution, technology, facilities and other infrastructure neededoperational needs to serve existing and expected demand.


Contractual Obligations


As of September 30, 2017,2021, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligations from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2016.2020.


Regulatory Matters
117


MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.



Quad Cities Generating Station Operating Status


Exelon Generation Company, LLC ("Exelon Generation"), 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 ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission creditsZECs will provide Exelon Generation 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 U.S. 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 in both suits and filed motions to dismiss in both matters. 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. The procedural schedule has been established for the appeals. MidAmerican Energy cannot predict the outcome of these lawsuits.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expandincludes a Minimum Offer Price Offer 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 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 in its order, 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 Exelon, 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 futurethat auction.

At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity auctionsmarket 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. A request for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms was filed on October 5, 2021, and remains pending.

Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator ofconsiders Quad Cities Station Exelon Generation has filed proteststo be at heightened risk for early retirement. However, to the FERC in response to each filing.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 timingFERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the FERC’s decision with respectIllinois zero emission standard unless the PJM adopts further changes to both proceedingsthe MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.

Regulatory Matters

MidAmerican Energy is currently unknown and the outcomesubject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of these matters is currently uncertain.this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.


118

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, 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. 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 the EPA and various 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 consolidated financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of MidAmerican Energy's forecast environmental-related capital expenditures.


Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.


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 Part I, Item 1 of this Form 10-Q.




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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2016.2020. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2016.

2020.

119

Nevada Power Company and its subsidiaries
Consolidated Financial Section




120

PART I
Item 1.Financial Statements

Item 1.Financial Statements



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Board of Directors and Shareholder of
Nevada Power Company
Las Vegas, Nevada

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2017, and2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 20172021 and 2016. These2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements areinformation for it to be in conformity with accounting principles generally accepted in the responsibilityUnited States of Nevada Power's management.America.


We conducted our reviewshave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2020, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States),PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.



/s/ Deloitte & Touche LLP




Las Vegas, Nevada
November 3, 20175, 2021




121

NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)


As of
September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$85 $25 
Trade receivables, net353 234 
Inventories66 69 
Derivative contracts3 26 
Regulatory assets217 48 
Prepayments37 38 
Other current assets36 26 
Total current assets797 466 
Property, plant and equipment, net6,829 6,701 
Finance lease right of use assets, net330 351 
Regulatory assets686 746 
Other assets73 72 
Total assets$8,715 $8,336 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$249 $181 
Accrued interest38 32 
Accrued property, income and other taxes60 25 
Current portion of finance lease obligations26 27 
Regulatory liabilities54 50 
Customer deposits44 47 
Asset retirement obligation16 25 
Other current liabilities38 22 
Total current liabilities525 409 
Long-term debt2,498 2,496 
Finance lease obligations313 334 
Regulatory liabilities1,118 1,163 
Deferred income taxes753 738 
Other long-term liabilities281 257 
Total liabilities5,488 5,397 
Commitments and contingencies (Note 8)00
Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding— — 
Additional paid-in capital2,308 2,308 
Retained earnings922 634 
Accumulated other comprehensive loss, net(3)(3)
Total shareholder's equity3,227 2,939 
Total liabilities and shareholder's equity$8,715 $8,336 
The accompanying notes are an integral part of the consolidated financial statements.
122
 As of
 September 30, December 31,
 2017 2016
ASSETS
Current assets:   
Cash and cash equivalents$69
 $279
Accounts receivable, net362
 243
Inventories59
 73
Regulatory assets34
 20
Other current assets50
 38
Total current assets574
 653
    
Property, plant and equipment, net6,890
 6,997
Regulatory assets1,110
 1,000
Other assets39
 39
    
Total assets$8,613
 $8,689
    
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:   
Accounts payable$192
 $187
Accrued interest39
 50
Accrued property, income and other taxes109
 93
Regulatory liabilities35
 37
Current portion of long-term debt and financial and capital lease obligations842
 17
Customer deposits78
 78
Other current liabilities31
 39
Total current liabilities1,326
 501
    
Long-term debt and financial and capital lease obligations2,231
 3,049
Regulatory liabilities423
 416
Deferred income taxes1,529
 1,474
Other long-term liabilities281
 277
Total liabilities5,790
 5,717
    
Commitments and contingencies (Note 9)
 
    
Shareholder's equity:   
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding—
 —
Other paid-in capital2,308
 2,308
Retained earnings518
 667
Accumulated other comprehensive loss, net(3) (3)
Total shareholder's equity2,823
 2,972
    
Total liabilities and shareholder's equity$8,613
 $8,689
    
The accompanying notes are an integral part of the consolidated financial statements.




NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)


Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Operating revenue$802 $808 $1,731 $1,706 
Operating expenses:
Cost of fuel and energy328 287 745 654 
Operations and maintenance88 139 228 295 
Depreciation and amortization103 92 304 273 
Property and other taxes12 12 36 35 
Total operating expenses531 530 1,313 1,257 
Operating income271 278 418 449 
Other income (expense):
Interest expense(38)(40)(115)(122)
Allowance for borrowed funds— 1 2 3 
Allowance for equity funds2 1 5 5 
Interest and dividend income5 3 13 8 
Other, net4 3 14 4 
Total other income (expense)(27)(32)(81)(102)
Income before income tax expense244 246 337 347 
Income tax expense27 52 36 74 
Net income$217 $194 $301 $273 
The accompanying notes are an integral part of these consolidated financial statements.

123
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Operating revenue$819
 $766
 $1,785
 $1,690
        
Operating costs and expenses:       
Cost of fuel, energy and capacity318
 251
 721
 618
Operating and maintenance97
 105
 278
 304
Depreciation and amortization77
 76
 231
 227
Property and other taxes10
 10
 29
 30
Total operating costs and expenses502
 442
 1,259
 1,179
        
Operating income317
 324
 526
 511
        
Other income (expense):       
Interest expense(44) (45) (132) (140)
Allowance for borrowed funds1
 —
 1
 2
Allowance for equity funds—
 —
 1
 3
Other, net5
 7
 18
 17
Total other income (expense)(38) (38) (112) (118)
        
Income before income tax expense279
 286
 414
 393
Income tax expense103
 98
 151
 136
Net income$176
 $188
 $263
 $257
        
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 (Unaudited)
(Amounts in millions, except shares)


Accumulated
AdditionalOtherTotal
Common StockPaid-inRetainedComprehensiveShareholder's
SharesAmountCapitalEarningsLoss, NetEquity
Balance, June 30, 20201,000 $— $2,308 $488 $(4)$2,792 
Net income— — — 194 — 194 
Balance, September 30, 20201,000 $— $2,308 $682 $(4)$2,986 
Balance, December 31, 20191,000 $— $2,308 $493 $(4)$2,797 
Net income— — — 273 — 273 
Dividends declared— — — (85)— (85)
Other equity transactions— — — 1 — 1 
Balance, September 30, 20201,000 $— $2,308 $682 $(4)$2,986 
Balance, June 30, 20211,000 $— $2,308 $705 $(3)$3,010 
Net income— — — 217 — 217 
Balance, September 30, 20211,000 $— $2,308 $922 $(3)$3,227 
Balance, December 31, 20201,000 $— $2,308 $634 $(3)$2,939 
Net income— — — 301 — 301 
Dividends declared— — — (13)— (13)
Balance, September 30, 20211,000 $— $2,308 $922 $(3)$3,227 
The accompanying notes are an integral part of these consolidated financial statements.

124
          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 —
 —
 —
 257
 —
 257
Dividends declared —
 —
 —
 (365) —
 (365)
Other equity transactions —
 —
 —
 (1) —
 (1)
Balance, September 30, 2016 1,000
 $—
 $2,308
 $749
 $(3) $3,054
             
Balance, December 31, 2016 1,000
 $—
 $2,308
 $667
 $(3) $2,972
Net income —
 —
 —
 263
 —
 263
Dividends declared —
 —
 —
 (412) —
 (412)
Balance, September 30, 2017 1,000
 $—
 $2,308
 $518
 $(3) $2,823
             
The accompanying notes are an integral part of these consolidated financial statements.




NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)


Nine-Month Periods
Ended September 30,
20212020
Cash flows from operating activities:
Net income$301 $273 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization304 273 
Allowance for equity funds(5)(5)
Changes in regulatory assets and liabilities(11)38 
Deferred income taxes and amortization of investment tax credits(19)(3)
Deferred energy(154)(38)
Amortization of deferred energy(7)(30)
Other, net1 5 
Changes in other operating assets and liabilities:
Trade receivables and other assets(133)(112)
Inventories3 (4)
Accrued property, income and other taxes28 48 
Accounts payable and other liabilities97 (39)
Net cash flows from operating activities405 406 
Cash flows from investing activities:
Capital expenditures(323)(343)
Proceeds from sale of assets— 26 
Other, net1 — 
Net cash flows from investing activities(322)(317)
Cash flows from financing activities:
Proceeds from long-term debt— 718 
Repayments of long-term debt— (575)
Dividends paid(13)(85)
Other, net(12)(12)
Net cash flows from financing activities(25)46 
Net change in cash and cash equivalents and restricted cash and cash equivalents58 135 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period36 25 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$94 $160 
The accompanying notes are an integral part of these consolidated financial statements.

125
 Nine-Month Periods
 Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income$263
 $257
Adjustments to reconcile net income to net cash flows from operating activities:   
Gain on nonrecurring items(1) —
Depreciation and amortization231
 227
Deferred income taxes and amortization of investment tax credits61
 52
Allowance for equity funds(1) (3)
Changes in regulatory assets and liabilities25
 139
Deferred energy(22) (3)
Amortization of deferred energy13
 (87)
Other, net(1) 3
Changes in other operating assets and liabilities:   
Accounts receivable and other assets(122) (96)
Inventories6
 7
Accrued property, income and other taxes11
 98
Accounts payable and other liabilities9
 7
Net cash flows from operating activities472
 601
    
Cash flows from investing activities:   
Capital expenditures(202) (249)
Acquisitions(77) —
Other, net4
 —
Net cash flows from investing activities(275) (249)
    
Cash flows from financing activities:   
Proceeds from issuance of long-term debt91
 —
Repayments of long-term debt and financial and capital lease obligations(86) (221)
Dividends paid(412) (365)
Net cash flows from financing activities(407) (586)
    
Net change in cash and cash equivalents(210) (234)
Cash and cash equivalents at beginning of period279
 536
Cash and cash equivalents at end of period$69
 $302
    
The accompanying notes are an integral part of these consolidated financial statements.




NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(1)    Organization and OperationsGeneral


Nevada Power Company, together with 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 the 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").


The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 20172021 and for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The results of operations for the three- and nine-month periods ended September 30, 20172021 are not necessarily indicative of the results to be expected for the full year.


The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Nevada Power's Annual Report on Form 10-K for the year ended December 31, 20162020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2017.2021.


(2)    New Accounting PronouncementsCash and Cash Equivalents and Restricted Cash and Cash Equivalents


In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendmentsCash equivalents consist of funds invested in this guidance require that an employer disaggregate the service cost component from themoney market mutual funds, United States Treasury Bills and other componentsinvestments with a maturity of net benefit costthree months or less when purchased. Cash 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. Nevada Power plans to adopt this guidance effective January 1, 2018. Nevada Power does not believe this will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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 andexclude amounts generally described aswhere availability is restricted cashby legal requirements, loan agreements or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included withother contractual provisions. Restricted cash and cash equivalents when reconcilingas of September 30, 2021 and December 31, 2020, consist of funds restricted by the beginning-of-periodPublic Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and end-of-period total amounts showncash equivalents and restricted cash and cash equivalents as of September 30, 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 statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Nevada Power plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.Balance Sheets (in millions):

As of
September 30,December 31,
20212020
Cash and cash equivalents$85 $25 
Restricted cash and cash equivalents included in other current assets9 11 
Total cash and cash equivalents and restricted cash and cash equivalents$94 $36 



126
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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Nevada Power plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will 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. 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 plans to adopt this guidance effective January 1, 2019 and is currently evaluating the 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 creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize 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. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. Nevada Power plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. Nevada Power currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power’s performance to date. Nevada Power's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by customer class.

(3)    Property, Plant and Equipment, Net


Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable LifeSeptember 30,December 31,
20212020
Utility plant:
Generation30 - 55 years$3,780 $3,690 
Transmission45 - 70 years1,493 1,468 
Distribution20 - 65 years3,878 3,771 
General and intangible plant5 - 65 years810 791 
Utility plant9,961 9,720 
Accumulated depreciation and amortization(3,350)(3,162)
Utility plant, net6,611 6,558 
Other non-regulated, net of accumulated depreciation and amortization45 years1 1 
Plant, net6,612 6,559 
Construction work-in-progress217 142 
Property, plant and equipment, net$6,829 $6,701 
   As of
 Depreciable Life September 30, December 31,
  2017 2016
Utility plant:     
Generation30 - 55 years $3,725
 $4,271
Distribution20 - 65 years 3,294
 3,231
Transmission45 - 65 years 1,860
 1,846
General and intangible plant5 - 65 years 784
 738
Utility plant  9,663
 10,086
Accumulated depreciation and amortization  (2,840) (3,205)
Utility plant, net  6,823
 6,881
Other non-regulated, net of accumulated depreciation and amortization45 years 2
 2
Plant, net  6,825
 6,883
Construction work-in-progress  65
 114
Property, plant and equipment, net  $6,890
 $6,997




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)    Regulatory Matters

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. 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. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Chapter 704B Applications

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 May 2015, MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed applications with the PUCN to purchase energy from alternative providers of a new electric resource and become distribution only service customers of Nevada Power. In December 2015, the PUCN granted the applications subject to conditions, including paying an impact fee, on-going charges and receiving approval for specific alternative energy providers and terms. In December 2015, the applicants filed petitions for reconsideration. In January 2016, the PUCN granted reconsideration and updated some of the terms, including removing a limitation related to energy purchased indirectly from NV Energy. In September 2016, MGM and Wynn paid impact fees of $82 million and $15 million, respectively. In October 2016, MGM and Wynn became distribution only service customers 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 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 May 2017, a stipulation reached between MGM, Regulatory Operations Staff and the Bureau of Consumer Protection was filed requiring Nevada Power to credit $16 million as an offset against MGM's remaining impact fee obligation and, in June 2017, the PUCN approved the stipulation as filed.

In September 2016, Switch, Ltd. ("Switch"), 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 December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions, including paying an impact fee to Nevada Power. In May 2017, Switch paid impact fees of $27 million and, in June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

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 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.



Emissions Reduction and Capacity Replacement 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 of Nevada Power's second amendment to the ERCR Plan. The remaining net book value 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 9 for additional information on the ERCR Plan.

(5) Recent Financing Transactions


In January 2017, Nevada Power (1) issued a notice to the bondholders for the repurchase of the remaining outstanding amounts of its $38 million Pollution Control Revenue Bonds, Series 2006 and $38 million Pollution Control Revenue Bonds, Series 2006A and (2) redeemed the Pollution Control Revenue Bonds, Series 2006A, aggregate principal amount outstanding plus accrued interest with the use of cash on hand. In February 2017, Nevada Power redeemed the Pollution Control Revenue Bonds, Series 2006, aggregate principal amount outstanding plus accrued interest with the use of cash on hand.Credit Facilities

In May 2017, Nevada Power entered into a Financing Agreement with Clark County, Nevada (the "Clark Issuer") whereby the Clark Issuer loaned to Nevada Power the proceeds from the issuance, on behalf of Nevada Power, of $39.5 million of its 1.60% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017, due 2036 ("Series 2017 Bonds"). The Series 2017 Bonds are subject to mandatory purchase by Nevada Power in May 2020, and on and after the purchase date, the interest rate may be adjusted from time to time.

In May 2017, Nevada Power entered into a Financing Agreement with the Coconino County, Arizona Pollution Control Corporation (the "Coconino Issuer") whereby the Coconino Issuer loaned to Nevada Power the proceeds from the issuance, on behalf of Nevada Power, of $40 million of its 1.80% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017A, due 2032 and $13 million of its 1.60% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017B, due 2039 (collectively, the "Series 2017AB Bonds"). The Series 2017AB Bonds are subject to mandatory purchase by Nevada Power in May 2020, and on and after the purchase date, the interest rate may be adjusted from time to time.

To provide collateral security for its obligations, Nevada Power issued its General and Refunding Mortgage Notes, Series AA, No. AA-1 in the amount of $39.5 million and No. AA-2 in the amount of $53 million (collectively, the "Series AA Notes").The obligation of Nevada Power to make any payment of the principal and interest on any Series AA Notes is discharged to the extent Nevada Power has made payment on the Series 2017 Bonds and the Series 2017AB Bonds.

The collective proceeds from the tax-exempt bond issuances were used to refund at par value, plus accrued interest, the Clark Issuer's $39.5 million of Pollution Control Refunding Revenue Bonds, Series 2006 and the Coconino Issuer's $40 million of Pollution Control Refunding Revenue Bonds, Series 2006A and $13 million of Pollution Control Refunding Revenue Bonds, Series 2006B, each previously issued on behalf of Nevada Power.


In June 2017,2021, Nevada Power amended and restated its existing $400 million secured credit facility extendingexpiring in June 2022 with no remaining one-year extension options. The amendment extended the maturityexpiration date to June 2020 with two one-year2024 and increased the available maturity extension options to an unlimited number, subject to lender consent. The amended 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 Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long-term debt securities. The amended credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not to exceed 0.65 to 1.0 as

(5)Income Taxes

A reconciliation of the last dayfederal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Effects of ratemaking(10)— (10)— 
Effective income tax rate11 %21 %11 %21 %

Effects of each quarter.ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2021.


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(6)    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 $1 million to the Non-Qualified Pension Plans for the nine-month period ended September 30, 2017. 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 payable toreceivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
As of
September 30,December 31,
20212020
Qualified Pension Plan:
Other non-current assets$11 $8 
Non-Qualified Pension Plans:
Other current liabilities(1)(1)
Other long-term liabilities(9)(9)
Other Postretirement Plans:
Other non-current assets4 4 
 As of
 September 30, December 31,
 2017 2016
Qualified Pension Plan -   
Other long-term liabilities$(27) $(24)
    
Non-Qualified Pension Plans:   
Other current liabilities(1) (1)
Other long-term liabilities(9) (9)
    
Other Postretirement Plans -   
Other long-term liabilities(4) (4)


(7)    Risk Management and Hedging ActivitiesFair Value Measurements

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, monitor and report 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 Note 8 for additional information on derivative contracts.



The following table, which excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power'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  
  Current Long-term  
  Liabilities Liabilities Total
As of September 30, 2017      
Commodity liabilities(1)
 $(3) $(1) $(4)
       
As of December 31, 2016      
Commodity liabilities(1)
 $(7) $(7) $(14)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates and as of September 30, 2017 and December 31, 2016, a regulatory asset of $4 million and $14 million, respectively, was recorded related to the derivative liability of $4 million and $14 million, respectively.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values (in millions):
   As of
 Unit of September 30, December 31,
 Measure 2017 2016
      
Electricity salesMegawatt hours —
 (2)
Natural gas purchasesDecatherms 149
 114

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, 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, 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 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 derivative contracts may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2017, credit ratings from the three 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 was $2 million as of September 30, 2017 and December 31, 2016, 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.



(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.


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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 1Level 2Level 3Total
As of September 30, 2021
Assets:
Commodity derivatives$— $— $4 $4 
Money market mutual funds74 — — 74 
Investment funds3 — — 3 
$77 $— $4 $81 
Liabilities - commodity derivatives$— $— $(18)$(18)
As of December 31, 2020
Assets:
Commodity derivatives$— $— $26 $26 
Money market mutual funds21 — — 21 
Investment funds2 — — 2 
$23 $— $26 $49 
Liabilities - commodity derivatives$— $— $(11)$(11)
 Input Levels for Fair Value Measurements  
 Level 1 Level 2 Level 3 Total
As of September 30, 2017       
Assets - investment funds$2
 $—
 $—
 $2
        
Liabilities - commodity derivatives$—
 $—
 $(4) $(4)
        
As of December 31, 2016       
Assets:       
Money market mutual funds(1)
$220
 $—
 $—
 $220
Investment funds6
 —
 —
 6
 $226
 $—
 $—
 $226
        
Liabilities - commodity derivatives$—
 $—
 $(14) $(14)

(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 September 30, 20172021 and December 31, 2016,2020, 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. Refer to Note 7 for further discussion regarding Nevada Power's risk management and hedging activities.




Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities andinvestment funds 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.


129

The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Beginning balance$25 $(44)$15 $(8)
Changes in fair value recognized in regulatory assets6 13 11 (31)
Settlements(45)31 (40)39 
Ending balance$(14)$— $(14)$— 
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
        
Beginning balance$(4) $(22) $(14) $(22)
Changes in fair value recognized in regulatory assets(1) (1) (3) (6)
Settlements1
 4
 13
 9
Ending balance$(4) $(19) $(4) $(19)


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 (in millions):
As of September 30, 2021As of December 31, 2020
CarryingFairCarryingFair
ValueValueValueValue
Long-term debt$2,498 $3,122 $2,496 $3,245 

(8)    Commitments and Contingencies
 As of September 30, 2017 As of December 31, 2016
 Carrying Fair Carrying Fair
 Value Value Value Value
        
Long-term debt$2,599
 $3,055
 $2,581
 $3,040

(9)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 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.

Consistent with the ERCR Plan, Nevada Power acquired a 272-MW natural gas co-generating facility in 2014, acquired a 210-MW natural gas peaking facility in 2014, constructed a 15-MW solar photovoltaic facility in 2015, contracted two renewable power purchase agreements with 100-MW solar photovoltaic generating facilities in 2015, contracted a renewable power purchase agreement with 100-MW solar photovoltaic generating facility in 2016 and acquired the remaining 130 MW, 25%, of the Silverhawk natural gas-fueled generating facility in April 2017, of which 54 MW were approved as part of the ERCR Plan. Nevada Power has the option to acquire 35 MW of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval. Nevada Power retired Reid Gardner Units 1, 2, and 3, 300 MW of coal-fueled generation, in 2014 and Reid Gardner Unit 4, 257 MW of coal-fueled generation, in March 2017. These transactions are related to Nevada Power's compliance with SB 123, resulting in the retirement of 812 MW of coal-fueled generation by 2019.


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.




Environmental Laws and Regulations

Nevada Power is subject to federal, state and local 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 Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

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(9)    Revenue from Contracts with Customers

The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Customer Revenue:
Retail:
Residential$477 $495 $998 $993 
Commercial129 127 323 317 
Industrial152 147 310 300 
Other4 3 10 8 
Total fully bundled762 772 1,641 1,618 
Distribution only service6 8 17 20 
Total retail768 780 1,658 1,638 
Wholesale, transmission and other28 21 57 48 
Total Customer Revenue796 801 1,715 1,686 
Other revenue6 7 16 20 
Total revenue$802 $808 $1,731 $1,706 


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Item 2.    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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.


Results of Operations for the Third Quarter and First Nine Months of 20172021 and 20162020


Overview

Net income for the third quarter of 20172021 was $176$217 million, a decreasean increase of $12$23 million, or 6%12%, compared to 20162020 primarily due to $51 million of lower operations and maintenance expenses, primarily due to lower commercialearnings sharing and industriallower net regulatory instructed deferrals and amortizations, $25 million of lower income tax expenses primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021 and $5 million of lower other expense. These increases are offset by $47 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue from customers purchasing energy from alternative providers and becoming distribution only service customers, refinement of the unbilled revenue estimate and increased other operating costs. The decrease in net income wasrecognized due to a favorable regulatory decision, partially offset by higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers, customer usage patterns, higher transmission revenue, and customer growth.$11 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 first nine months of 20172021 was $263$301 million, an increase of $6$28 million, or 2%10%, compared to 20162020 primarily due to $67 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations, lower earnings sharing and costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation, $38 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, $10 million of higher other, retail revenue primarily from impact feesnet, mainly due to lower pension expense and revenue relating to customers becoming distribution only service customers,higher cash surrender value of corporate-owned life insurance policies, lower interest on deferred chargesexpense of $7 million and long-term debt, customer growth,higher interest and dividend income of $5 million. These increases are offset by $66 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, partially offset by price impacts from changes in sales mix, an increase in the average number of customers and higher transmission revenue, customer usage patterns and lower planned maintenance. The increase in net income was partially offset by lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers,$31 million of higher depreciation and amortization, primarilymainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in-service and increased other operating costs.in service.


Operating revenue and cost of fuel, energy and capacity
132

Non-GAAP Financial Measure

Management utilizes various key financial measures that are key drivers of Nevada Power'sprepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operationsoperations. Utility margin is calculated as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. Nevada Power believes that a discussion of gross margin, representingelectric 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 capacity,energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses 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 sales 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 therefore meaningful.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):

Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin:
Operating revenue$802 $808 $(6)(1)%$1,731 $1,706 $25 1 %
Cost of fuel and energy328 287 41 14 745 654 91 14 
Utility margin474 521 (47)(9)986 1,052 (66)(6)
Operations and maintenance88 139 (51)(37)228 295 (67)(23)
Depreciation and amortization103 92 11 12 304 273 31 11 
Property and other taxes12 12 — — 36 35 1 3 
Operating income$271 $278 $(7)(3)%$418 $449 $(31)(7)%


133

Utility Margin

A comparison of Nevada Power's key operating results related to utility margin is as follows:
Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$802 $808 $(6)(1)%$1,731 $1,706 $25 1 %
Cost of fuel and energy328 287 41 14 745 654 91 14 
Utility margin$474 $521 $(47)(9)%$986 $1,052 $(66)(6)%
Sales (GWhs):
Residential4,343 4,378 (35)(1)%8,737 8,557 180 2 %
Commercial1,568 1,471 97 7 3,793 3,553 240 7 
Industrial1,611 1,477 134 9 3,978 3,735 243 7 
Other52 48 4 8 144 142 2 1 
Total fully bundled(1)
7,574 7,374 200 3 16,652 15,987 665 4 
Distribution only service787 664 123 19 1,923 1,776 147 8 
Total retail8,361 8,038 323 4 18,575 17,763 812 5 
Wholesale93 82 11 13 266 316 (50)(16)
Total GWhs sold8,454 8,120 334 4 %18,841 18,079 762 4 %
Average number of retail customers (in thousands)988 970 18 2 %983 966 17 2 %
Average revenue per MWh:
Retail - fully bundled(1)
$100.56 $104.72 $(4.16)(4)%$98.54 $101.21 $(2.67)(3)%
Wholesale$90.60 $78.36 $12.24 16 %$61.65 $41.28 $20.37 49 %
Heating degree days— — — —1,008 984 24 2 %
Cooling degree days2,447 2,537 (90)(4)%3,930 3,847 83 2 %
Sources of energy (GWhs)(2)(3):
Natural gas4,776 4,888 (112)(2)%10,857 10,628 229 2 %
Renewables19 18 1 6 55 54 1 2 
Total energy generated4,795 4,906 (111)(2)10,912 10,682 230 2 
Energy purchased2,727 2,366 361 15 6,186 5,532 654 12 
Total7,522 7,272 250 3 %17,098 16,214 884 5 %
Average cost of energy per MWh(4):
Energy generated$24.71 $11.83 $12.88 *$21.49 $16.00 $5.49 34 %
Energy purchased$76.77 $96.51 $(19.74)(20)%$82.53 $87.27 $(4.74)(5)%
*    Not meaningful
(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 163 GWhs and 152 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 1,095 GWhs and 1,180 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2021 and 2020, respectively.
(3)    GWh amounts are net of energy used by the related generating facilities.
(4)    The average cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.
134

  Third Quarter First Nine Months 
  2017 2016 Change 2017 2016 Change
Gross margin (in millions):                
Operating revenue $819
 $766
 $53
7
% $1,785
 $1,690
 $95
6
%
Cost of fuel, energy and capacity 318
 251
 67
27
  721
 618
 103
17
 
Gross margin $501
 $515
 $(14)(3)  $1,064
 $1,072
 $(8)(1) 
                 
GWh sold:                
Residential 3,899
 3,814
 85
2
% 7,899
 7,802
 97
1
%
Commercial 1,517
 1,440
 77
5
  3,669
 3,600
 69
2
 
Industrial 1,783
 2,149
 (366)(17)  4,870
 5,772
 (902)(16) 
Other 60
 59
 1
2
  154
 155
 (1)(1) 
Total fully bundled(1)
 7,259
 7,462
 (203)(3)  16,592
 17,329
 (737)(4) 
Distribution only service 617
 119
 498
*
  1,367
 305
 1,062
*
 
Total retail 7,876
 7,581
 295
4
  17,959
 17,634
 325
2
 
Wholesale 59
 76
 (17)(22)  214
 177
 37
21
 
Total GWh sold 7,935
 7,657
 278
4
  18,173
 17,811
 362
2
 
                 
Average number of retail customers (in thousands):                
Residential 813
 799
 14
2
% 809
 795
 14
2
%
Commercial 106
 105
 1
1
  106
 105
 1
1
 
Industrial 2
 2
 —
—
  2
 2
 —
—
 
Total 921
 906
 15
2
  917
 902
 15
2
 
                 
Average retail revenue per MWh:                
Fully bundled(1)
 $109.85
 $101.22
 $8.63
9
% $104.06
 $95.69
 $8.37
9
%
                 
Heating degree days —
 —
 —
—
% 791
 829
 (38)(5)%
Cooling degree days 2,319
 2,295
 24
1
% 3,808
 3,674
 134
4
%
                 
Sources of energy (GWh)(2):
                
Natural gas 4,592
 4,657
 (65)(1)% 10,338
 11,569
 (1,231)(11)%
Coal 367
 599
 (232)(39)  1,182
 1,140
 42
4
 
Renewables 19
 26
 (7)(27)  57
 47
 10
21
 
Total energy generated 4,978
 5,282
 (304)(6)  11,577
 12,756
 (1,179)(9) 
Energy purchased 2,500
 2,471
 29
1
  5,665
 5,410
 255
5
 
Total 7,478
 7,753
 (275)(4)  17,242
 18,166
 (924)(5) 
                 
Average total cost of energy per MWh(3):
 $42.46
 $32.30
 $10.16
31
% $41.80
 $34.01
 $7.79
23
%
Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020

*     Not meaningful
(1)Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2)GWh amounts are net of energy used by the related generating facilities.
(3)The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.



GrossUtility margin decreased $14$47 million, or 3%9%, for the third quarter of 20172021 compared to 20162020 primarily due to:
•$1527 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$20 million of lower revenue recognized due to a favorable regulatory decision in lower commercial and industrial retail revenue2020,
•$3 million due to price impacts from customers purchasing energy from alternative providers and becomingchanges in sales mix. Retail customer volumes, including distribution only service customers;customers, increased 4.0% primarily due to favorable changes in customer usage patterns, offset by the unfavorable impact of weather,
•$103 million indue to lower energy efficiency program revenuerates (offset in operatingoperations and maintenance expense) and
•$91 million fromof lower other revenue due to a refinementregulatory amortization of the unbilled revenue estimate.an impact fee that ended December 2020.
The decrease in grossutility margin was offset by:
$8 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;
•$5 million from customer usage patterns;
$3 million inof higher transmission revenue primarily due to customers becoming distribution only service customers and
•$23 million due to an increase in the average number of customers, primarily from the residential customer growth.class.


OperatingOperations and maintenance decreased $8$51 million, or 8%37%, for the third quarter of 20172021 compared to 20162020 primarily due to lower earnings sharing, lower net regulatory instructed deferrals and amortizations, 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 January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation, costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation and lower energy efficiency program expensecosts (offset in operating revenue).

Depreciation and amortization increased $11 million, or 12%, for the third quarter of $8 million.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.


Income taxInterest expense increased $5 decreased $2 million, or 5%, for the third quarter of 20172021 compared to 2016.2020 primarily due to lower carrying charges on regulatory balances.

Interest and dividend income increased $2 million, or 67%, for the third quarter of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Other, net increased $1 million, or 33%, for the third quarter of 2021 compared to 2020 primarily due to lower pension expense, partially offset by lower cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $25 million, or 48%, for the third quarter of 2021 compared to 2020. The effective tax rate was 37%11% in 20172021 and 34%21% in 2016. The increase in the effective tax rate is2020 and decreased primarily due to the qualified production activities deduction in 2016.recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.


Gross
135

First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020

Utility margin decreased $8$66 million, or 1%6%, for the first nine months of 20172021 compared to 20162020 primarily due to:
•$2451 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$20 million of lower revenue recognized due to a favorable regulatory decision in 2020,
•$7 million due to lower commercialenergy efficiency program rates (offset in operations and industrial retailmaintenance expense),
•$6 million due to an adjustment to regulatory-related revenue deferrals and
•$3 million due to a regulatory amortization of an impact fee that ended December 2020.
The decrease in utility margin was offset by:
•$11 million due to price impacts from customers purchasing energy from alternative providers and becomingchanges in sales mix. Retail customer volumes, including distribution only service customers, increased 4.6% primarily due to favorable changes in customer usage patterns and the favorable impact of weather,
•$22 million in lower energy efficiency program revenue (offset in operating and maintenance expense).
The decrease in gross margin was offset by:
$19 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;
$75 million due to an increase in the average number of customers, primarily from the residential customer growth;class and
•$65 million inof higher transmission revenue primarily due to customers becoming distribution only service customers andrevenue.
$5 million from customer usage patterns.

OperatingOperations and maintenance decreased $26$67 million, or 9%23%, for the first nine months of 20172021 compared to 20162020 primarily due to lower net regulatory instructed deferrals and amortizations, 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 January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation, lower earnings sharing, lower energy efficiency program expensecosts (offset in operating revenue); lower planned maintenance; and decreased expenses related to uncollectible accounts. These decreases are partially offset by higher other operating costs.costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation.


Depreciation and amortizationincreased$4 million, or 2%, for the first nine months of 2017 compared to 2016 primarily due to higher plant placed in-service.

Other income (expense) is favorable $6 million, or 5%, for the first nine months of 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.

Income tax expense increased $15$31 million, or 11%, for the first nine months of 20172021 compared to 2016.2020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.

Interest expense decreased $7 million, or 6%, for the first nine months of 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances of $5 million and lower interest expense on long-term debt.

Interest and dividend income increased $5 million, or 63%, for the first nine months of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Other, net increased $10 million for the first nine months of 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 $38 million, or (51)%, for the first nine months of 2021 compared to 2020. The effective tax rate was 36%11% in 20172021 and 35%21% in 2016. The increase in the effective tax rate is2020 and decreased primarily due to the qualified production activities deduction in 2016.recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.



136



Liquidity and Capital Resources


As of September 30, 2017,2021, Nevada Power's total net liquidity was $469 million consisting of $69 million in cash and cash equivalents and $400 million of a credit facility.as follows (in millions):


Cash and cash equivalents$85 
Credit facility400 
Total net liquidity$485 
Credit facility:
Maturity date2024

Operating Activities


Net cash flows from operating activities for the nine-month periods ended September 30, 20172021 and 20162020 were $472$405 million and $601$406 million, respectively. The change was primarily due to higher impact fees received in 2016the timing of payments for fuel and energy costs and higher intercompany tax payments for income taxes, partially offset by a 2016 contribution to the pension plan.

In December 2015, the Protecting Americanshigher collections from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, Nevada Power's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.

Thecustomers, timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methodspayments for operating costs, increased collections of customer advances and assumptions for each payment date.lower inventory purchases.


Investing Activities


Net cash flows from investing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $(275)$(322) million and $(249)$(317) million, respectively. The change was primarily due to the acquisitionincreased capital expenditures. Refer to "Future Uses of the remaining 25% in the Silverhawk generating station, partially offset by decreasedCash" for further discussion of capital expenditures.


Financing Activities


Net cash flows from financing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $(407)$(25) million and $(586)$46 million, respectively. The change was primarily due to lower repayments of long‑term debt and proceeds from the issuance of long‑termlong-term debt, partially offset by higherlower repayments of long-term debt and lower dividends paid to NV Energy, Inc. in 2017.

Ability to Issue Debt Authorizations


Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2017, Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) issue new long-termestablish debt securitiesissuances limited to a debt ceiling of up to $1.3 billion;$3.2 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) refinance up to $1.2 billion of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. Nevada Power's revolving credit facility contains a financial maintenance covenant which Nevada Power was in compliancecurrently has an effective automatic shelf registration statement with asthe SEC to issue an indeterminate amount of September 30, 2017.general and refunding mortgage securities through October 2022.


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 its secured revolving credit facility, 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 regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.




Capital Expenditures


Nevada Power 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, 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.

137

Nevada Power's historicalHistorical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Electric distribution$182 $137 $194 
Electric transmission27 38 67 
Solar generation— 7 21 
Other134 141 208 
Total$343 $323 $490 
 Nine-Month Periods Annual
 Ended September 30, Forecast
 2016 2017 2017
      
Generation development$1
 $—
 $—
Distribution110
 41
 58
Transmission system investment29
 6
 10
Other109
 155
 180
Total$249
 $202
 $248


Nevada Power's approved Fourth Amendment to the 2018 Joint IRP included an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates may change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include investments relatedthe 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 thatprimarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program of which costs are split 70% to Nevada Power and 30% to Sierra Pacific. In this project, the company proposed 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. Construction of the project was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to build 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 Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West. Operating expenditures consist of routine expenditures for transmission distribution, generation and other infrastructure needed to serve existing and expected demand.

In April 2017, Nevada Power purchased•Solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the remaining 25% interest in the Silverhawk natural gas-fueledDry Lake generating facility, that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other investments include both growth projects and operating expenditures consisting of routine expenditures 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 allocatedgeneration, other operating projects and other infrastructure needed to the assets acquired, consisting primarily of generation utility plant,serve existing and no significant liabilities were assumed.expected demand.


Contractual Obligations


As of September 30, 2017,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2016.2020.


138

Regulatory Matters


Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's 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, RPS, 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. 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 the EPA and various 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 Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.


Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws.laws and regulations.




New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting Nevada Power, refer to Note 2 of Notes to Consolidated Financial Statements in Nevada Power's Part I, Item 1 of this Form 10-Q.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2016.2020. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2016.

2020.

139

Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section




140

PART I
Item 1.Financial Statements

Item 1.Financial Statements



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Las Vegas, Nevada

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of September 30, 2017, and2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 20172021 and 2016,2020, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 20172021 and 2016. These2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements areinformation for it to be in conformity with accounting principles generally accepted in the responsibilityUnited States of Sierra Pacific's management.America.


We conducted our reviewshave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2020, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States),PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Sierra Pacific Power Company and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.



/s/ Deloitte & Touche LLP




Las Vegas, Nevada
November 3, 20175, 2021




141

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)


As of
September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$14 $19 
Trade receivables, net118 97 
Inventories68 77 
Regulatory assets168 67 
Other current assets48 45 
Total current assets416 305 
Property, plant and equipment, net3,265 3,164 
Regulatory assets265 267 
Other assets184 183 
Total assets$4,130 $3,919 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$121 $108 
Accrued interest11 14 
Accrued property, income and other taxes18 14 
Short-term debt127 45 
Regulatory liabilities23 34 
Customer deposits15 15 
Other current liabilities31 25 
Total current liabilities346 255 
Long-term debt1,164 1,164 
Finance lease obligations116 121 
Regulatory liabilities446 463 
Deferred income taxes396 374 
Other long-term liabilities144 131 
Total liabilities2,612 2,508 
Commitments and contingencies (Note 8)00
Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding— — 
Additional paid-in capital1,111 1,111 
Retained earnings408 301 
Accumulated other comprehensive loss, net(1)(1)
Total shareholder's equity1,518 1,411 
Total liabilities and shareholder's equity$4,130 $3,919 
The accompanying notes are an integral part of the consolidated financial statements.

142
 As of
 September 30, December 31,
 2017 2016
ASSETS
Current assets:   
Cash and cash equivalents$30
 $55
Accounts receivable, net102
 117
Inventories47
 45
Regulatory assets38
 25
Other current assets20
 13
Total current assets237
 255
    
Property, plant and equipment, net2,862
 2,822
Regulatory assets400
 410
Other assets8
 6
    
Total assets$3,507
 $3,493
    
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:   
Accounts payable$75
 $146
Accrued interest11
 14
Accrued property, income and other taxes11
 10
Regulatory liabilities17
 69
Current portion of long-term debt and financial and capital lease obligations1
 1
Customer deposits15
 16
Other current liabilities18
 12
Total current liabilities148
 268
    
Long-term debt and financial and capital lease obligations1,151
 1,152
Regulatory liabilities223
 221
Deferred income taxes663
 617
Other long-term liabilities134
 127
Total liabilities2,319
 2,385
    
Commitments and contingencies (Note 8)
 
    
Shareholder's equity:   
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding—
 —
Other paid-in capital1,111
 1,111
Retained earnings (deficit)78
 (2)
Accumulated other comprehensive loss, net(1) (1)
Total shareholder's equity1,188
 1,108
    
Total liabilities and shareholder's equity$3,507
 $3,493
    
The accompanying notes are an integral part of the consolidated financial statements.




SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)


Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Operating revenue:
Regulated electric$266 $220 $636 $569 
Regulated natural gas16 15 75 83 
Total operating revenue282 235 711 652 
Operating expenses:
Cost of fuel and energy120 81 295 233 
Cost of natural gas purchased for resale6 4 35 44 
Operations and maintenance40 40 117 123 
Depreciation and amortization35 36 107 104 
Property and other taxes6 6 18 17 
Total operating expenses207 167 572 521 
Operating income75 68 139 131 
Other income (expense):
Interest expense(14)(14)(41)(42)
Allowance for borrowed funds1 — 2 1 
Allowance for equity funds2 1 5 3 
Interest and dividend income3 1 6 3 
Other, net3 2 9 4 
Total other income (expense)(5)(10)(19)(31)
Income before income tax expense70 58 120 100 
Income tax expense8 6 13 10 
Net income$62 $52 $107 $90 
The accompanying notes are an integral part of these consolidated financial statements.

143
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Operating revenue:       
Electric$215
 $207
 $534
 $539
Natural gas15
 15
 66
 81
Total operating revenue230
 222
 600
 620
        
Operating costs and expenses:       
Cost of fuel, energy and capacity76
 73
 193
 208
Natural gas purchased for resale4
 5
 26
 42
Operating and maintenance40
 40
 121
 126
Depreciation and amortization29
 30
 85
 88
Property and other taxes6
 5
 18
 18
Total operating costs and expenses155
 153
 443
 482
        
Operating income75
 69
 157
 138
        
Other income (expense):       
Interest expense(11) (12) (33) (42)
Allowance for borrowed funds1
 —
 1
 1
Allowance for equity funds1
 1
 2
 2
Other, net2
 2
 4
 3
Total other income (expense)(7) (9) (26) (36)
        
Income before income tax expense68
 60
 131
 102
Income tax expense24
 22
 46
 37
Net income$44
 $38
 $85
 $65
        
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 (Unaudited)
(Amounts in millions, except shares)


Accumulated
AdditionalOtherTotal
Common StockPaid-inRetainedComprehensiveShareholder's
SharesAmountCapitalEarningsLoss, NetEquity
Balance, June 30, 20201,000 $— $1,111 $228 $(1)$1,338 
Net income— — — 52 — 52 
Balance, September 30, 20201,000 $— $1,111 $280 $(1)$1,390 
Balance, December 31, 20191,000 $— $1,111 $210 $(1)$1,320 
Net income— — — 90 — 90 
Dividends declared— — — (20)— (20)
Balance, September 30, 20201,000 $— $1,111 $280 $(1)$1,390 
Balance, June 30, 20211,000 $— $1,111 $346 $(1)$1,456 
Net income— — — 62 — 62 
Balance, September 30, 20211,000 $— $1,111 $408 $(1)$1,518 
Balance, December 31, 20201,000 $— $1,111 $301 $(1)$1,411 
Net income— — — 107 — 107 
Balance, September 30, 20211,000 $— $1,111 $408 $(1)$1,518 
The accompanying notes are an integral part of these consolidated financial statements.

144
          Accumulated  
      Other Retained Other Total
  Common Stock Paid-in Earnings Comprehensive Shareholder's
  Shares Amount Capital (Deficit) Loss, Net Equity
             
Balance, December 31, 2015 1,000
 $—
 $1,111
 $(35) $—
 $1,076
Net income —
 —
 —
 65
 —
 65
Dividends declared —
 —
 —
 (45) —
 (45)
Other equity transactions —
 —
 —
 —
 (1) (1)
Balance, September 30, 2016 1,000
 $—
 $1,111
 $(15) $(1) $1,095
             
Balance, December 31, 2016 1,000
 $—
 $1,111
 $(2) $(1) $1,108
Net income —
 —
 —
 85
 —
 85
Dividends declared —
 —
 —
 (5) —
 (5)
Balance, September 30, 2017 1,000
 $—
 $1,111
 $78
 $(1) $1,188
             
The accompanying notes are an integral part of these consolidated financial statements.




SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)


Nine-Month Periods
Ended September 30,
20212020
Cash flows from operating activities:
Net income$107 $90 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization107 104 
Allowance for equity funds(5)(3)
Changes in regulatory assets and liabilities(30)(30)
Deferred income taxes and amortization of investment tax credits10 3 
Deferred energy(95)(5)
Amortization of deferred energy12 (6)
Other, net(1)— 
Changes in other operating assets and liabilities:
Trade receivables and other assets(25)(83)
Inventories9 (18)
Accrued property, income and other taxes3 8 
Accounts payable and other liabilities21 119 
Net cash flows from operating activities113 179 
Cash flows from investing activities:
Capital expenditures(196)(192)
Net cash flows from investing activities(196)(192)
Cash flows from financing activities:
Proceeds from long-term debt— 30 
Net proceeds from short-term debt82 — 
Dividends paid— (20)
Other, net(5)(3)
Net cash flows from financing activities77 7 
Net change in cash and cash equivalents and restricted cash and cash equivalents(6)(6)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period26 32 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$20 $26 
The accompanying notes are an integral part of these consolidated financial statements.

145
 Nine-Month Periods
 Ended September 30,
 2017 2016
Cash flows from operating activities:   
Net income$85
 $65
Adjustments to reconcile net income to net cash flows from operating activities:   
Depreciation and amortization85
 88
Allowance for equity funds(2) (2)
Deferred income taxes and amortization of investment tax credits46
 37
Changes in regulatory assets and liabilities9
 (14)
Deferred energy(23) 55
Amortization of deferred energy(43) (35)
Other, net—
 (1)
Changes in other operating assets and liabilities:   
Accounts receivable and other assets13
 12
Inventories(2) 1
Accrued property, income and other taxes(2) —
Accounts payable and other liabilities(54) (15)
Net cash flows from operating activities112
 191
    
Cash flows from investing activities:   
Capital expenditures(131) (137)
Net cash flows from investing activities(131) (137)
    
Cash flows from financing activities:   
Proceeds from issuance of long-term debt, net of costs—
 1,089
Repayments of long-term debt and financial and capital lease obligations(1) (1,137)
Dividends paid(5) (45)
Net cash flows from financing activities(6) (93)
    
Net change in cash and cash equivalents(25) (39)
Cash and cash equivalents at beginning of period55
 106
Cash and cash equivalents at end of period$30
 $67
    
The accompanying notes are an integral part of these consolidated financial statements.




SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


(1)    Organization and OperationsGeneral


Sierra Pacific Power Company, together with 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").


The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 20172021 and for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 20172021 and 2016.2020. The results of operations for the three- and nine-month periods ended September 30, 20172021 are not necessarily indicative of the results to be expected for the full year.


The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 20162020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Sierra Pacific's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2017.2021.


(2)    New Accounting PronouncementsCash and Cash Equivalents and Restricted Cash and Cash Equivalents


In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendmentsCash equivalents consist of funds invested in this guidance require that an employer disaggregate the service cost component from themoney market mutual funds, United States Treasury Bills and other componentsinvestments with a maturity of net benefit costthree months or less when purchased. Cash 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. Sierra Pacific plans to adopt this guidance effective January 1, 2018. Sierra Pacific does not believe this will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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 andexclude amounts generally described aswhere availability is restricted cashby legal requirements, loan agreements or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included withother contractual provisions. Restricted cash and cash equivalents when reconcilingas of September 30, 2021 and December 31, 2020, consist of funds restricted by the beginning-of-periodPublic Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and end-of-period total amounts showncash equivalents and restricted cash and cash equivalents as of September 30, 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 statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Sierra Pacific plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.Balance Sheets (in millions):

As of
September 30,December 31,
20212020
Cash and cash equivalents$14 $19 
Restricted cash and cash equivalents included in other current assets6 7 
Total cash and cash equivalents and restricted cash and cash equivalents$20 $26 



146
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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Sierra Pacific plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will 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. 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 plans to adopt this guidance effective January 1, 2019 and is currently evaluating the 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 creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize 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. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. Sierra Pacific plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. Sierra Pacific currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific’s performance to date. Sierra Pacific's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by segment and customer class.



(3)    Property, Plant and Equipment, Net


Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable LifeSeptember 30,December 31,
20212020
Utility plant:
Electric generation25 - 60 years$1,140 $1,130 
Electric transmission50 - 100 years914 908 
Electric distribution20 - 100 years1,806 1,754 
Electric general and intangible plant5 - 70 years199 189 
Natural gas distribution35 - 70 years433 429 
Natural gas general and intangible plant5 - 70 years15 15 
Common general5 - 70 years361 355 
Utility plant4,868 4,780 
Accumulated depreciation and amortization(1,834)(1,755)
Utility plant, net3,034 3,025 
Other non-regulated, net of accumulated depreciation and amortization70 years— 2 
Plant, net3,034 3,027 
Construction work-in-progress231 137 
Property, plant and equipment, net$3,265 $3,164 

   As of
 Depreciable Life September 30, December 31,
  2017 2016
Utility plant:     
Electric generation25 - 60 years $1,140
 $1,137
Electric distribution20 - 100 years 1,445
 1,417
Electric transmission50 - 100 years 782
 771
Electric general and intangible plant5 - 70 years 182
 164
Natural gas distribution35 - 70 years 388
 381
Natural gas general and intangible plant5 - 70 years 14
 15
Common general5 - 70 years 290
 267
Utility plant  4,241
 4,152
Accumulated depreciation and amortization  (1,496) (1,442)
Utility plant, net  2,745
 2,710
Other non-regulated, net of accumulated depreciation and amortization70 years 5
 5
Plant, net  2,750
 2,715
Construction work-in-progress  112
 107
Property, plant and equipment, net  $2,862
 $2,822

During 2016, Sierra Pacific revised its electric and gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was shorter estimated useful lives at the Valmy Generating Station. The effect of this change will increase depreciation and amortization expense by $9 million annually based on depreciable plant balances at the time of the change. However, the Public Utilities Commission of Nevada ("PUCN") ordered the change relating to the Valmy Generating Station of $7 million annually be deferred for future recovery through a regulatory asset.

(4)    Regulatory Matters

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. 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. 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 Review

In June 2016, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving most, but not all, issues in the proceeding and reduced Sierra Pacific's electric revenue requirement by $3 million spread evenly to all rate classes. In December 2016, the PUCN approved the settlement agreement and established an additional six MW of net metering capacity under the grandfathered rates, which are those net metering rates that were in effect prior to January 2016; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. The new rates were effective January 1, 2017. In January 2017, Sierra Pacific filed a petition for reconsideration relating to the creation of the additional six megawatts ("MW") of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision result in additional cost shifting to non-net metering customers and reduces the stipulated rate reduction for other customer classes. In June 2017, the PUCN denied the petition for reconsideration.



In June 2016, Sierra Pacific filed a gas regulatory rate review with the PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving all issues in the proceeding and reduced Sierra Pacific's gas revenue requirement by $2 million. In December 2016, the PUCN approved the settlement agreement. The new rates were effective January 1, 2017.

Chapter 704B Applications

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 September 2016, Switch, Ltd. ("Switch"), 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 December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions. In June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

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 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 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.

(5)Recent Financing Transactions


Credit Facilities

In June 2017,2021, Sierra Pacific amended and restated its existing $250 million secured credit facility extendingexpiring in June 2022 with no remaining one-year extension options. The amendment extended the maturityexpiration date to June 2020 with two one-year2024 and increased the available maturity extension options to an unlimited number, subject to lender consent. The amended 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. The amended credit facility requires Sierra Pacific's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as

(5)Income Taxes

A reconciliation of the last dayfederal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Effects of ratemaking(10)(11)(10)(10)
Other— — — (1)
Effective income tax rate11 %10 %11 %10 %

Effects of each quarter.ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.


147

(6)    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 $4$1 million to the Other Postretirement Plans for the nine-month period ended September 30, 2017.2021. 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 (in millions):
As of
September 30,December 31,
20212020
Qualified Pension Plan:
Other non-current assets$31 $26 
Non-Qualified Pension Plans:
Other current liabilities(1)(1)
Other long-term liabilities(8)(8)
Other Postretirement Plans:
Other long-term liabilities(13)(13)

 As of
 September 30, December 31,
 2017 2016
Qualified Pension Plan -   
Other long-term liabilities$(13) $(12)
    
Non-Qualified Pension Plans:   
Other current liabilities(1) (1)
Other long-term liabilities(9) (9)
    
Other Postretirement Plans -   
Other long-term liabilities(25) (28)

(7)    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.


148

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 1Level 2Level 3Total
As of September 30, 2021
Assets:
Commodity derivatives$— $— $2 $2 
Money market mutual funds11 — — 11 
Investment funds1 — — 1 
$12 $— $2 $14 
Liabilities - commodity derivatives$— $— $(2)$(2)
As of December 31, 2020
Assets:
Commodity derivatives$— $— $9 $9 
Money market mutual funds17 — — 17 
$17 $— $9 $26 
Liabilities - commodity derivatives$— $— $(2)$(2)
 Input Levels for Fair Value Measurements  
 Level 1 Level 2 Level 3 Total
As of September 30, 2017       
Assets - investment funds$—
 $—
 $—
 $—
        
As of December 31, 2016       
Assets:       
Money market mutual funds(1)
$35
 $—
 $—
 $35
Investment funds1
 —
 —
 1
 $36
 $—
 $—
 $36

(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.




Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities andinvestment funds 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 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 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 (in millions):
As of September 30, 2021As of December 31, 2020
CarryingFairCarryingFair
ValueValueValueValue
Long-term debt$1,164 $1,328 $1,164 $1,358 

149

 As of September 30, 2017 As of December 31, 2016
 Carrying Fair Carrying Fair
 Value Value Value Value
        
Long-term debt$1,120
 $1,201
 $1,119
 $1,191
(8)    Commitments and Contingencies

(8)
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 consolidated financial results.


Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local 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 Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

(9)    Revenue from Contracts with Customers

The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 10 (in millions):
Three-Month Periods
Ended September 30,
20212020
ElectricNatural GasTotalElectricNatural GasTotal
Customer Revenue:
Retail:
Residential$91 $11 $102 $76 $11 $87 
Commercial84 3 87 71 3 74 
Industrial71 2 73 57 1 58 
Other1 — 1 1 — 1 
Total fully bundled247 16 263 205 15 220 
Distribution only service1 — 1 1 — 1 
Total retail248 16 264 206 15 221 
Wholesale, transmission and other18 — 18 13 — 13 
Total Customer Revenue266 16 282 219 15 234 
Other revenue— — — 1 — 1 
Total revenue$266 $16 $282 $220 $15 $235 

150

Nine-Month Periods
Ended September 30,
20212020
ElectricNatural GasTotalElectricNatural GasTotal
Customer Revenue:
Retail:
Residential$229 $50 $279 $208 $54 $262 
Commercial202 18 220 183 20 203 
Industrial151 6 157 132 8 140 
Other4 — 4 3 — 3 
Total fully bundled586 74 660 526 82 608 
Distribution only service2 — 2 3 — 3 
Total retail588 74 662 529 82 611 
Wholesale, transmission and other46 — 46 37 — 37 
Total Customer Revenue634 74 708 566 82 648 
Other revenue2 1 3 3 1 4 
Total revenue$636 $75 $711 $569 $83 $652 

151

(10)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.

Sierra Pacific believes presenting gross margin allows the reader to assess the impact of Sierra Pacific's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale ("cost of sales").




The following tables provide information on a reportable segment basis (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Operating revenue:
Regulated electric$266 $220 $636 $569 
Regulated natural gas16 15 75 83 
Total operating revenue$282 $235 $711 $652 
Operating income:
Regulated electric$74 $66 $126 $119 
Regulated natural gas1 2 13 12 
Total operating income75 68 139 131 
Interest expense(14)(14)(41)(42)
Allowance for borrowed funds1 — 2 1 
Allowance for equity funds2 1 5 3 
Interest and dividend income3 1 6 3 
Other, net3 2 9 4 
Income before income tax expense$70 $58 $120 $100 

As of
September 30,December 31,
20212020
Assets:
Regulated electric$3,744 $3,540 
Regulated natural gas354 342 
Other(1)
32 37 
Total assets$4,130 $3,919 

(1)    Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
152
 Three-Month Periods Nine-Month Periods
 Ended September 30, Ended September 30,
 2017 2016 2017 2016
Operating revenue:       
Regulated electric$215
 $207
 $534
 $539
Regulated gas15
 15
 66
 81
Total operating revenue$230
 $222
 $600
 $620
        
Cost of sales:       
Regulated electric$76
 $73
 $193
 $208
Regulated gas4
 5
 26
 42
Total cost of sales$80
 $78
 $219
 $250
        
Gross margin:       
Regulated electric$139
 $134
 $341
 $331
Regulated gas11
 10
 40
 39
Total gross margin$150
 $144
 $381
 $370
        
Operating and maintenance:       
Regulated electric$36
 $36
 $108
 $112
Regulated gas4
 4
 13
 14
Total operating and maintenance$40
 $40
 $121
 $126
        
Depreciation and amortization:       
Regulated electric$25
 $26
 $74
 $76
Regulated gas4
 4
 11
 12
Total depreciation and amortization$29
 $30
 $85
 $88
        
Operating income:       
Regulated electric$72
 $68
 $142
 $127
Regulated gas3
 1
 15
 11
Total operating income$75
 $69
 $157
 $138
        
Interest expense:       
Regulated electric$10
 $11
 $30
 $38
Regulated gas1
 1
 3
 4
Total interest expense$11
 $12
 $33
 $42





   As of
     September 30, December 31,
     2017 2016
Assets:       
Regulated electric    $3,165
 $3,119
Regulated gas    305
 314
Regulated common assets(1)
    37
 60
Total assets    $3,507
 $3,493

(1)Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.


Item 2.    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 and resources. Sierra Pacific 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 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 consolidated 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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.


Results of Operations for the Third Quarter and First Nine Monthsof 20172021 and 20162020


Overview


Net income for the third quarter of 20172021 was $44$62 million, an increase of $6$10 million, or 16%19%, compared to 20162020 primarily due to a decrease in interest expense from lower rates on outstanding debt balances and on deferred charges,$7 million of higher electric margins primarilyutility margin, mainly from increased customer usage due to theprice impacts from changes in sales mix and higher transmission and wholesale revenue, and $2 million of weatherhigher interest and customer usage patterns and decreased other operating costs. The increase in netdividend income, was partially offset by lower wholesale revenue.mainly from carrying charges on regulatory balances.


Net income for the first nine months of 20172021 was $85$107 million, an increase of $20$17 million, or 31%19%, compared to 20162020 primarily due to a decrease in interest expense from$6 million of lower rates on outstanding debt balancesoperations and on deferred charges,maintenance expenses, mainly due to lower plant operations and maintenance expenses and lower earnings sharing, $5 million of higher electric marginsutility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from increasedthe residential customer usage due to the impacts of weather and customer usage patterns, higher transmission revenue and lower other operating costs. The increase in net income wasclass, partially offset by lower wholesale revenue.revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, $5 million of higher other, net, mainly due to lower pension costs and higher cash surrender value of corporate-owned life insurance policies, and $3 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, partially offset by $3 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant in service, and $3 million of higher income tax expense primarily due to higher pretax income.


OperatingNon-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 capacity andcost of natural gas purchased for resale are key drivers ofgenerally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's results of operations as they encompass retail and wholesale electricityexpenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the direct costs associated with providing electricitypresentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to customers. Sierra Pacific believes thatrunning the business and a discussionmeasure of grosscomparability to others in the industry.
153

Electric utility margin representing operating revenue less cost of fuel, energy and capacity and natural gas purchasedutility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, resale,operating income which is therefore meaningful.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):

Third QuarterFirst Nine Months
20212020Change20212020Change
Electric utility margin:
Operating revenue$266 $220 $46 21 %$636 $569 $67 12 %
Cost of fuel and energy120 81 39 48 295 233 62 27 
Electric utility margin146 139 7 5 341 336 5 1 
Natural gas utility margin:
Operating revenue16 15 1 7 %75 83 (8)(10)%
Natural gas purchased for resale6 4 2 50 35 44 (9)(20)
Natural gas utility margin10 11 (1)(9)40 39 1 3 
Utility margin156 150 6 4 %381 375 6 2 %
Operations and maintenance40 40 — — %117 123 (6)(5)%
Depreciation and amortization35 36 (1)(3)107 104 3 3 
Property and other taxes6 6 — — 18 17 1 6 
Operating income$75 $68 $7 10 %$139 $131 $8 6 %


154

Electric Utility Margin

A comparison of Sierra Pacific's key operating results related to electric utility margin is as follows:

Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$266 $220 $46 21 %$636 $569 $67 12 %
Cost of fuel and energy120 81 39 48 295 233 62 27 
Utility margin$146 $139 $7 5 %$341 $336 $5 1 %
Sales (GWhs):
Residential828 796 32 4 %2,125 2,016 109 5 %
Commercial897 865 32 4 2,362 2,288 74 3 
Industrial989 923 66 7 2,786 2,643 143 5 
Other4 4 — — 11 12 (1)(8)
Total fully bundled(1)
2,718 2,588 130 5 7,284 6,959 325 5 
Distribution only service403 422 (19)(5)1,220 1,259 (39)(3)
Total retail3,121 3,010 111 4 8,504 8,218 286 3 
Wholesale204 87 117 *504 376 128 34 
Total GWhs sold3,325 3,097 228 7 %9,008 8,594 414 5 %
Average number of retail customers (in thousands)366 359 7 2 %365 358 7 2 %
Average revenue per MWh:
Retail - fully bundled(1)
$91.05 $79.22 $11.83 15 %$80.56 $75.65 $4.91 6 %
Wholesale$48.32 $79.72 $(31.40)(39)%$53.39 $54.54 $(1.15)(2)%
Heating degree days411526 *2,737 2,672 65 2 %
Cooling degree days997 946 51 5 %1,366 1,166 200 17 %
Sources of energy (GWhs)(2)(3):
Natural gas1,463 1,587 (124)(8)%3,678 3,967 (289)(7)%
Coal373 496 (123)(25)%838 716 122 17 %
Renewables(4)
8 12 (4)(33)27 31 (4)(13)
Total energy generated1,844 2,095 (251)(12)4,543 4,714 (171)(4)
Energy purchased1,383 1,173 210 18 3,905 3,625 280 8 
Total3,227 3,268 (41)(1)%8,448 8,339 109 1 %
Average cost of energy per MWh(5):
Energy generated$23.64 $13.75 $9.89 72 %$24.11 $21.13 $2.98 14 %
Energy purchased$55.46 $44.97 $10.49 23 %$47.52 $36.83 $10.69 29 %
Electric Gross Margin*    Not meaningful
(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 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2021 and 2020, respectively.
(3)    GWh amounts are net of energy used by the related generating facilities.
(4)    Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.
(5)    The average cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.
155
  Third Quarter First Nine Months
  2017 2016 Change 2017 2016 Change
Gross margin (in millions):                
Operating electric revenue $215
 $207
 $8
4
% $534
 $539
 $(5)(1)%
Cost of fuel, energy and capacity 76
 73
 3
4
  193
 208
 (15)(7) 
Gross margin $139
 $134
 $5
4
  $341
 $331
 $10
3
 
                 
GWh sold:                
Residential 736
 694
 42
6
% 1,904
 1,798
 106
6
%
Commercial 850
 854
 (4)—
  2,271
 2,241
 30
1
 
Industrial 797
 747
 50
7
  2,346
 2,235
 111
5
 
Other 4
 4
 —
—
  12
 12
 —
—
 
Total fully bundled(1)
 2,387
 2,299
 88
4
  6,533

6,286

247
4
 
Distribution only service 348
 346
 2
1
  1,041

1,019

22
2
 
Total retail 2,735
 2,645
 90
3
  7,574
 7,305
 269
4
 
Wholesale 103
 147
 (44)(30)  392
 481
 (89)(19) 
Total GWh sold 2,838
 2,792
 46
2
  7,966
 7,786
 180
2
 
                 
Average number of retail customers (in thousands):                
Residential 295
 292
 3
1
% 295
 291
 4
1
%
Commercial 47
 47
 —
—
  47
 47
 —
—
 
Total 342
 339
 3
1
  342
 338
 4
1
 
                 
Average revenue per MWh:                
Retail fully bundled(1)
 $85.07
 $84.77
 $0.30
—
% $75.89
 $79.90
 $(4.01)(5)%
Wholesale $61.21
 $52.33
 $8.88
17
  $52.92

$50.96

$1.96
4
 
                 
Heating degree days 118
 43
 75
*
% 2,823
 2,487
 336
14
%
Cooling degree days 1,070
 796
 274
34
% 1,401
 1,088
 313
29
%
                 
Sources of energy (GWh)(2):
                
Natural gas 1,221
 1,215
 6
—
% 3,227

3,195

32
1
%
Coal 355
 392
 (37)(9)  457
 691
 (234)(34) 
Renewables 12
 —
 12
*
  31

—

31
*
 
Total energy generated 1,588
 1,607
 (19)(1)  3,715
 3,886
 (171)(4) 
Energy purchased 1,074
 878
 196
22
  3,698
 3,111
 587
19
 
Total 2,662
 2,485
 177
7
  7,413
 6,997
 416
6
 
                 
Average total cost of energy per MWh(3):
 $28.53
 $29.67
 $(1.14)(4)% $26.07

$29.82

$(3.75)(13)%


*     Not meaningful
(1)Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2)GWh amounts are net of energy used by the related generating facilities.
(3)The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.



Natural Gas GrossUtility Margin

  Third Quarter  First Nine Months 
  2017 2016 Change 2017 2016 Change
Gross margin (in millions):                
Operating natural gas revenue $15
 $15
 $—
—
% $66
 $81
 $(15)(19)%
Natural gas purchased for resale 4
 5
 (1)(20)  26
 42
 (16)(38) 
Gross margin $11
 $10
 $1
10
  $40
 $39
 $1
3
 
                 
Dth sold:                
Residential 835
 727
 108
15
% 6,866
 5,958
 908
15
%
Commercial 494
 459
 35
8
  3,522
 3,182
 340
11
 
Industrial 244
 216
 28
13
  1,255
 1,080
 175
16
 
Total retail 1,573
 1,402
 171
12
  11,643
 10,220
 1,423
14
 
                 
Average number of retail customers (in thousands) 164
 162
 2
1
% 164
 161
 3
2
%
Average revenue per retail Dth sold $8.59
 $10.22
 $(1.63)(16)% $5.47
 $7.68
 $(2.21)(29)%
Average cost of natural gas per retail Dth sold $2.53
 $3.11
 $(0.58)(19)% $2.20
 $4.09
 $(1.89)(46)%
Heating degree days 118
 43
 75
*
% 2,823
 2,487
 336
14
%
A comparison of key operating results related to natural gas utility margin is as follows:

Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$16 $15 $1 7 %$75 $83 $(8)(10)%
Natural gas purchased for resale6 4 2 50 35 44 (9)(20)
Utility margin$10 $11 $(1)(9)%$40 $39 $1 3 %
Sold (000's Dths):
Residential774 786 (12)(2)%6,882 6,724 158 2 %
Commercial471 424 47 11 3,550 3,309 241 7 
Industrial274 249 25 10 1,414 1,244 170 14 
Total retail1,519 1,459 60 4 %11,846 11,277 569 5 %
Average number of retail customers (in thousands)177 174 3 2 %177 174 3 2 %
Average revenue per retail Dth sold$10.51 $9.89 $0.62 6 %$6.30 $7.33 $(1.03)(14)%
Heating degree days41 15 26 *2,737 2,672 65 2 %
Average cost of natural gas per retail Dth sold$3.78 $3.01 $0.77 26 %$2.97 $3.93 $(0.96)(24)%
*    Not meaningful

Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020

Electric grossutility marginincreased$7 million, or 5%, for the third quarter of 2021 compared to 2020 primarily due to:
•$5 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased $53.7% primarily due to favorable changes in customer usage patterns and the favorable impact of weather,
•$2 million of higher transmission and wholesale revenue and
•$1 million due to an increase in the average number of customers, primarily from the residential customer class.

Interest and dividend income increased $2 million for the third quarter of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Income tax expense increased $2 million, or 4%33%, for the third quarter of 20172021 compared to 2016 due to:
$4 million higher customer usage primarily from the impacts of weather and
$3 million from customer usage patterns.
The increase in electric gross margin was partially offset by:
$2 million in decreased wholesale revenue due to lower volumes.

Other income (expense) is favorable $2 million, or 22%, for the third quarter of 2017 compared to 20162020, primarily due to lower interest on deferred charges.

Income tax expense increased $2 million, or 9%, for the third quarter of 2017 compared to 2016.higher pretax income. The effective tax rate was 35%11% in 20172021 and 37%10% in 2016.2020.


156

First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020

Electric grossutility marginincreased$5 million, or 1%, for the first nine months of 2021 compared to 2020 primarily due to:
•$9 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased $103.5% primarily due to favorable changes in customer usage patterns and the favorable impact of weather,
•$2 million due to an increase in the average number of customers, primarily from the residential customer class and
•$2 million of higher transmission and wholesale revenue.
The increase in 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
•$1 million due to lower energy efficiency program rates (offset in operations and maintenance expense).

Operations and maintenance decreased $6 million, or 3%5%, for the first nine months of 20172021 compared to 2016 due to:
$8 million higher customer usage2020 primarily from the impacts of weather;
$3 million from customer usage patterns and
$2 million in higher transmission revenue.
The increase in electric gross margin was partially offset by:
$4 million in decreased wholesale revenue due to lower volumes.

Operatingplant operations and maintenance decreased $5 million, or 4%, for the first nine months of 2017 compared to 2016 due toexpenses, lower otherearnings sharing and lower energy efficiency program costs (offset in operating costs, partially offset by lower operating and maintenance related regulatory credit amortizations.revenue).


Depreciation and amortizationdecreased increased $3 million, or 3%, for the first nine months of 20172021 compared to 20162020 primarily due to regulatory amortizations.amortizations and higher plant in service.


Interest and dividend income increased $3 million for the first nine months of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Other, income (expense) is favorable $10net increased $5 million for the first nine months of 2021 compared to 2020 primarily due to lower pension costs and higher cash surrender value of corporate-owned life insurance policies.

Income tax expense increased $3 million, or 28%30%, for the first nine months of 20172021 compared to 20162020, primarily due to a decrease in interest expense from lower rates on outstanding debt balances and lower interest on deferred charges.



Income tax expense increased $9 million, or 24%, for the first nine months of 2017 compared to 2016.higher pretax income. The effective tax rate was 35%11% in 20172021 and 36%10% in 2016.2020.


Liquidity and Capital Resources


As of September 30, 2017,2021, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents$14 
Credit facility250 
Less -
Short-term debt(127)
Net credit facility123 
Total net liquidity$137 
Credit facility:
Maturity date2024
Cash and cash equivalents $30
   
Credit facility 250
Less:  
Tax-exempt bond support (80)
Net credit facility 170
   
Total net liquidity $200


Operating Activities


Net cash flows from operating activities for the nine-month periods ended September 30, 20172021 and 20162020 were $112$113 million and $191$179 million, respectively. The change was primarily due to higherthe timing of payments for fuel and energy costs, partially offset by higher collections from customers, lower contributions to the pension plan.inventory purchases and increased collections of customer advances.

157
In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, Sierra Pacific's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.


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 and assumptions for each payment date.

Investing Activities


Net cash flows from investing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $(131)$(196) million and $(137)$(192) million, respectively. The change was primarily due to decreasedincreased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.


Financing Activities


Net cash flows from financing activities for the nine-month periods ended September 30, 20172021 and 20162020 were $(6)$77 million and $(93)$7 million, respectively. The change was primarily due to lower repayments of long-termhigher proceeds from short-term debt and lower dividends paid to NV Energy, Inc. in 2017, partially offset by lower proceeds from the issuance of long-term debt.


Ability to Issue Debt Authorizations


Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2017, Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) issue additional long-termestablish debt securitiesissuances limited to a debt ceiling of up to $350 million;$1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) refinance up to $55 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $600 million. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of September 30, 2017.




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 its secured revolving credit facility, 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 regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.


Capital Expenditures


Sierra Pacific 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, 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.


Sierra Pacific's historicalHistorical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Electric distribution$101 $66 $113 
Electric transmission51 50 90 
Solar generation— — 18 
Other40 80 118 
Total$192 $196 $339 
 Nine-Month Periods Annual
 Ended September 30, Forecast
 2016 2017 2017
      
Distribution$73
 $61
 $91
Transmission system investment16
 9
 14
Other48
 61
 80
Total$137
 $131
 $185


Sierra Pacific's approved Fourth Amendment to the 2018 Joint IRP included an increase in electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates may 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.
158

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to operating projects thatthe Nevada Utilities' Greenlink Nevada transmission expansion program of which costs are split 70% to Nevada Power and 30% to Sierra Pacific. In this project, the company proposed 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. Construction of the project was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to build 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 Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West. Operating expenditures consist of routine expenditures for transmission distribution, generation and other infrastructure needed to serve existing and expected demand.

•Other investments include both growth projects and operating expenditures consisting of routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

Contractual Obligations


As of September 30, 2017,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2016.2020.


Regulatory Matters


Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's 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, RPS, 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. 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 the EPA and various 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 Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.




Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.


New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting Sierra Pacific, refer to Note 2 of Notes to Consolidated Financial Statements in Sierra Pacific's Part I, Item 1 of this Form 10-Q.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2016.2020. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2016.2020.




159

Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
160

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors of
Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of September 30, 2021, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and nine-month periods ended September 30, 2021 and 2020, and of cash flows for the nine-month periods ended September 30, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Eastern Energy Gas as of December 31, 2020, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Eastern Energy Gas' management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Richmond, Virginia
November 5, 2021

161

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
September 30, 2021December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents$90 $35 
Restricted cash and cash equivalents17 13 
Trade receivables, net143 177 
Receivables from affiliates70 139 
Income taxes receivable52 20 
Other receivables7 51 
Inventories127 119 
Prepayments90 60 
Natural gas imbalances69 26 
Other current assets19 16 
Total current assets684 656 
Property, plant and equipment, net10,195 10,144 
Goodwill1,286 1,286 
Investments259 244 
Other assets167 291 
Total assets$12,591 $12,621 

The accompanying notes are an integral part of these consolidated financial statements.
162

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

As of
September 30, 2021December 31, 2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$71 $71 
Accounts payable to affiliates35 39 
Accrued interest49 19 
Accrued property, income and other taxes73 29 
Notes payable— 9 
Current portion of long-term debt— 500 
Other current liabilities178 147 
Total current liabilities406 814 
Long-term debt3,910 3,925 
Regulatory liabilities646 669 
Other long-term liabilities239 218 
Total liabilities5,201 5,626 
Commitments and contingencies (Note 9)00
Equity:
Member's equity:
Membership interests3,388 2,957 
Accumulated other comprehensive loss, net(42)(53)
Total member's equity3,346 2,904 
Noncontrolling interests4,044 4,091 
Total equity7,390 6,995 
Total liabilities and equity$12,591 $12,621 

The accompanying notes are an integral part of these consolidated financial statements.
163

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Operating revenue$456 $531 $1,379 $1,597 
Operating expenses:
(Excess) cost of gas(3)14 (13)23 
Operations and maintenance125 119 362 922 
Depreciation and amortization83 95 244 282 
Property and other taxes38 38 115 109 
Total operating expenses243 266 708 1,336 
Operating income213 265 671 261 
Other income (expense):
Interest expense(32)(186)(118)(294)
Allowance for equity funds2 1 5 11 
Interest and dividend income— 10 — 67 
Other, net(1)11 1 39 
Total other income (expense)(31)(164)(112)(177)
Income before income tax expense (benefit) and equity income182 101 559 84 
Income tax expense (benefit)21 (10)70 (40)
Equity income8 7 31 30 
Net income169 118 520 154 
Net income attributable to noncontrolling interests100 32 302 97 
Net income attributable to Eastern Energy Gas$69 $86 $218 $57 

The accompanying notes are an integral part of these consolidated financial statements.
164

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)


Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Net income$169 $118 $520 $154 
 
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $(1), $— and $—— (4)4 (1)
Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $37, $2 and $8(2)111 11 24 
Total other comprehensive (loss) income, net of tax(2)107 15 23 
 
Comprehensive income167 225 535 177 
Comprehensive income attributable to noncontrolling interests100 32 306 97 
Comprehensive income attributable to Eastern Energy Gas$67 $193 $229 $80 

The accompanying notes are an integral part of these consolidated financial statements.
165

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)

Accumulated
Other
MembershipComprehensiveNoncontrollingTotal
InterestsLoss, NetInterestsEquity
Balance, June 30, 2020$7,352 $(271)$1,375 $8,456 
Net income86 — 32 118 
Other comprehensive income— 107 — 107 
Contributions299 — — 299 
Distributions(2,394)— (36)(2,430)
Balance, September 30, 2020$5,343 $(164)$1,371 $6,550 
Balance, December 31, 2019$9,031 $(187)$1,385 $10,229 
Net income57 — 97 154 
Other comprehensive income— 23 — 23 
Contributions299 — — 299 
Distributions(4,044)— (111)(4,155)
Balance, September 30, 2020$5,343 $(164)$1,371 $6,550 
Balance, June 30, 2021$3,366 $(40)$4,072 $7,398 
Net income69 — 100 169 
Other comprehensive loss— (2)— (2)
Contributions2 — — 2 
Distributions(49)— (128)(177)
Balance, September 30, 2021$3,388 $(42)$4,044 $7,390 
Balance, December 31, 2020$2,957 $(53)$4,091 $6,995 
Net income218 — 302 520 
Other comprehensive income— 11 4 15 
Contributions284 — — 284 
Distributions(71)— (353)(424)
Balance, September 30, 2021$3,388 $(42)$4,044 $7,390 

The accompanying notes are an integral part of these consolidated financial statements.
166

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Nine-Month Periods
Ended September 30,
20212020
Cash flows from operating activities:
Net income$520 $154 
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net(9)463 
Depreciation and amortization244 282 
Allowance for equity funds(5)(11)
Equity (income) loss, net of distributions(1)33 
Changes in regulatory assets and liabilities(2)19 
Deferred income taxes135 (103)
Other, net(11)8 
Changes in other operating assets and liabilities:
Trade receivables and other assets13 271 
Derivative collateral, net7 148 
Pension and other postretirement benefit plans— (46)
Accrued property, income and other taxes(61)36 
Accounts payable and other liabilities37 5 
Net cash flows from operating activities867 1,259 
Cash flows from investing activities:
Capital expenditures(291)(258)
Repayment of loans by affiliates269 3,422 
Loans to affiliates(170)(225)
Other, net(9)(9)
Net cash flows from investing activities(201)2,930 
Cash flows from financing activities:
Repayments of long-term debt(500)— 
Net repayments of short-term debt— (62)
Repayment of notes payable, net(9)(253)
Proceeds from equity contributions256 299 
Distributions(353)(4,155)
Other, net(1)(1)
Net cash flows from financing activities(607)(4,172)
Net change in cash and cash equivalents and restricted cash and cash equivalents59 17 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period48 39 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$107 $56 

The accompanying notes are an integral part of these consolidated financial statements.
167

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)    General

Eastern Energy Gas Holdings, LLC and its subsidiaries ("Eastern Energy Gas") is a holding company that 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.

In July 2020, Dominion Energy, Inc. ("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 Berkshire Hathaway Energy Company ("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 acquisition of substantially all of the natural gas transmission and storage business of 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") and the proposed sale of 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 Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have 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. On November 1, 2020, BHE completed 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").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2021 and for the three- and nine-month periods ended September 30, 2021 and 2020. The results of operations for the three- and nine-month periods ended September 30, 2021 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2021.

168

(2)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of
September 30,December 31,
Depreciable Life20212020
Utility Plant:
Interstate natural gas pipeline assets24 - 43 years$8,555 $8,382 
Intangible plant5 - 10 years111 115 
Utility plant in service8,666 8,497 
Accumulated depreciation and amortization(2,859)(2,759)
Utility plant in service, net5,807 5,738 
Nonutility Plant:
LNG facility40 years4,466 4,454 
Intangible plant14 years25 25 
Nonutility plant in service4,491 4,479 
Accumulated depreciation and amortization(396)(283)
Nonutility plant in service, net4,095 4,196 
Plant, net9,902 9,934 
Construction work-in-progress293 210 
Property, plant and equipment, net$10,195 $10,144 

Construction work-in-progress includes $266 million and $196 million as of September 30, 2021 and December 31, 2020, respectively, related to the construction of utility plant.

169

(3)    Investments and Restricted Cash and Cash Equivalents

Investments and restricted cash and cash equivalents consists of the following (in millions):
As of
September 30,December 31,
20212020
Investments:
Investment funds$13 $— 
Equity method investments:
Iroquois246 244 
Total investments259 244 
Restricted cash and cash equivalents:
Customer deposits17 13 
Total restricted cash and cash equivalents17 13 
Total investments and restricted cash and cash equivalents$276 $257 
Reflected as:
Current assets$17 $13 
Noncurrent assets259 244 
Total investments and restricted cash and cash equivalents$276 $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 September 30, 2021 and December 31, 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 received distributions from its investments of $30 million and $63 million for the nine-month periods ended September 30, 2021 and 2020, respectively.


170

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 September 30, 2021 and December 31, 2020 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 of September 30, 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
September 30,December 31,
20212020
Cash and cash equivalents$90 $35 
Restricted cash and cash equivalents17 13 
Total cash and cash equivalents and restricted cash and cash equivalents$107 $48 

(4)    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 rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion. EGTS has 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 of $129 million ($94 million after-tax) for the year ended December 31, 2018 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) estimated charge for disallowance of capitalized allowance for funds used during construction. 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 allowance for funds used during construction, 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 its Consolidated Statements 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 Statements of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million asset retirement obligation. 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 asset retirement obligation, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statements of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.
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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, 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 $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.

(5)    Recent Financing Transactions

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. The following table details the exchanged notes prior to, and subsequent to, the transaction (in millions):

Prior to ExchangeSubsequent to Exchange
Eastern Energy Gas Par ValueEastern Energy Gas Par ValueEGTS Par Value
3.6% Senior Notes due 2024$450 $339 $111 
3.0% Senior Notes due 2029600 174 426 
4.8% Senior Notes due 2043400 54 346 
4.6% Senior Notes due 2044500 56 444 
3.9% Senior Notes due 2049300 27 273 
$2,250 $650 $1,600 

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(6)    Income Taxes

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:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
State income tax, net of federal income tax benefit2 (3)2 (29)
Equity interest1 — 1 8 
Effects of ratemaking(1)(2)(1)(6)
Change in tax status— (18)— (24)
AFUDC-equity— — — (2)
Noncontrolling interest(11)(6)(11)(24)
Write-off of regulatory assets— — — 9 
Other, net— (2)1 (1)
Effective income tax rate12 %(10)%13 %(48)%

Noncontrolling interest is attributable to Eastern Energy Gas' ownership in Cove Point. The GT&S Transaction resulted in a change of noncontrolling interest to 75% as of September 30, 2021 from 25% as of September 30, 2020. Additionally, Eastern Energy Gas' effective tax rate for the periods ended September 30, 2020 is primarily a function of the impacts associated with the cancellation of the Atlantic Coast Pipeline project, the nominal year-to-date pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries.

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. Subsequent to the GT&S Transaction, Eastern Energy Gas, as a subsidiary of BHE, is included in Berkshire Hathaway's United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provisions for income tax have been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. Eastern Energy Gas received net cash payments for income tax from BHE totaling $34 million for the nine-month period ended September 30, 2021.

(7)    Employee 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. Also prior to the GT&S Transaction, pension benefits for Eastern Energy Gas employees represented by collective bargaining units were provided by a separate plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Company ("MidAmerican Energy") Pension Plan, similar to the DEI plan.

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. Also prior to the GT&S Transaction, retiree health 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. Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Retiree Health and Welfare plan, similar to the DEI plan.
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Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Pension:
Service cost$— $2 $— $5 
Interest cost— 3 — 8 
Expected return on plan assets— (14)— (42)
Net amortization— 1 — 5 
Net periodic benefit credit$— $(8)$— $(24)
Other Postretirement:
Service cost$— $— $— $1 
Interest cost— 1 — 3 
Expected return on plan assets— (4)— (14)
Net amortization— (1)— (2)
Net periodic benefit credit$— $(4)$— $(12)

(8)    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.


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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 1Level 2Level 3Total
As of September 30, 2021
Assets:
Foreign currency exchange rate derivatives$— $8 $— $8 
Money market mutual funds75 — — 75 
Investment funds13 — — 13 
$88 $8 $— $96 
Liabilities:
Commodity derivatives$— $(1)$— $(1)
Foreign currency exchange rate derivatives— (4)— (4)
$— $(5)$— $(5)
As of December 31, 2020
Assets:
Foreign currency exchange rate derivatives$— $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.


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Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. 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 (in millions):

As of September 30, 2021As of December 31, 2020
CarryingFairCarryingFair
ValueValueValueValue
Long-term debt$3,910 $4,327 $4,425 $5,012 

(9)    Commitments and Contingencies

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.

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. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.

(10)    Revenue from Contracts with Customers

The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Customer Revenue:
Regulated:
Gas transportation and storage$249 $311 $774 $957 
Wholesale14 25 31 27 
Other1 1 (1)4 
Total regulated264 337 804 988 
Nonregulated193 193 573 606 
Total Customer Revenue457 530 1,377 1,594 
Other revenue(1)1 2 3 
Total operating revenue$456 $531 $1,379 $1,597 


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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 September 30, 2021 (in millions):
Performance obligations expected to be satisfied
Less than 12 monthsMore than 12 monthsTotal
Eastern Energy Gas$1,574 $16,413 $17,987 

(11)    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 tax (in millions):

UnrecognizedAccumulated
Amounts OnUnrealizedOther
RetirementLosses on CashNoncontrollingComprehensive
BenefitsFlow HedgesInterestsLoss, Net
Balance, December 31, 2019$(106)$(81)$— $(187)
Other comprehensive (loss) income(1)24 — 23 
Balance, September 30, 2020$(107)$(57)$— $(164)
Balance, December 31, 2020$(12)$(51)$10 $(53)
Other comprehensive income (loss)4 11 (4)11 
Balance, September 30, 2021$(8)$(40)$6 $(42)

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 were probable of not occurring as a result of the GT&S Transaction.

(12)    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.

In November 2019, 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 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.


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Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $3 million for each of the three-month periods ended September 30, 2021 and 2020, and $9 million and $10 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $31 million and $22 million as of September 30, 2021 and December 31, 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 $7 million and $21 million for the three- and nine-month periods ended September 30, 2020, 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 $22 million and $80 million for the three- and nine-month periods ended September 30, 2020, 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.

(13)    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 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. Eastern Energy Gas participated in certain DEI benefit plans as described in Note 7.

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 three-month and nine-month periods ended September 30, 2020 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.


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Presented below are Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliated and related parties for the three- and nine-month periods ended September 30, 2020 (in millions):

Three-Month PeriodNine-Month Period
Ended September 30, 2020Ended September 30, 2020
Sales of natural gas and transportation and storage services$60 $188 
Purchases of natural gas and transportation and storage services3 9 
Services provided by related parties(1)
34 114 
Services provided to related parties(2)
17 78 
(1)    Includes capitalized expenditures of $5 million and $12 million for the three- and nine-month periods ended September 30, 2020, respectively.
(2)    Amounts primarily attributable to Atlantic Coast Pipeline, LLC, a related-party VIE prior to the GT&S Transaction.

Interest income related to the affiliated notes receivable under the DEI money pool was $3 million for the nine-month period ended September 30, 2020.

Interest income related to Eastern Energy Gas' affiliated notes receivable from DEI was $9 million and $32 million for the three- and nine-month periods ended September 30, 2020, respectively.

Interest income related to Eastern Energy Gas' affiliated notes receivable from East Ohio Gas Company was $33 million for the nine-month period ended September 30, 2020.

Interest charges related to Eastern Energy Gas' total borrowings under an intercompany revolving credit agreement with DEI were $3 million for the nine-month period ended September 30, 2020.

Interest charges related to CPMLP Holdings Company, LLC's total borrowings from DES were $3 million for the nine-month period ended September 30, 2020.

For the nine-month period ended September 30, 2020, Eastern Energy Gas distributed $4.2 billion to DEI.

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 $31 million and $20 million as of September 30, 2021 and December 31, 2020, respectively.

Other assets included amounts due from an affiliate of $4 million and $7 million as of September 30, 2021 and December 31, 2020, respectively.

As of September 30, 2021, Eastern Energy Gas had $3 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 three- and nine-month periods ended September 30, 2021 (in millions):

Three-Month PeriodNine-Month Period
Ended September 30, 2021Ended September 30, 2021
Sales of natural gas and transportation and storage services$7 $21 
Purchases of natural gas and transportation and storage services1 4 
Services provided by related parties16 31 
Services provided to related parties8 24 
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Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, LLC ("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 September 30, 2021 and December 31, 2020, $— million and $9 million, respectively, was outstanding under the credit agreement.

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 September 30, 2021 and December 31, 2020, $28 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 7. As of September 30, 2021 and December 31, 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 $110 million and $115 million, respectively.



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Item 2.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 Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2021 and 2020

Overview

Net income attributable to Eastern Energy Gas for the third quarter of 2021 was $69 million, a decrease of $17 million compared to 2020. Net income decreased primarily due to an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point LNG, LP ("Cove Point") of $68 million, the November 2020 disposition of Questar Pipeline Group of $26 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $14 million, all of which were a result of the GT&S Transaction, and income tax expense of $21 million in 2021 versus income tax benefit of $10 million in 2020, primarily due to higher pre-tax income. These decreases were partially offset by 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.

Net income attributable to Eastern Energy Gas for the first nine months of 2021 was $218 million, an increase of $161 million compared to 2020. Net income increased 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"), 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 and higher margins of $39 million due to favorable natural gas prices. These increases were partially offset by a decrease in net income due to an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point of $205 million, the November 2020 disposition of Questar Pipeline Group of $68 million, interest income from DEI and its affiliates recognized in 2020 of $65 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $42 million, all of which were a result of the GT&S Transaction, and income tax expense of $70 million in 2021 versus income tax benefit of $40 million in 2020, primarily due to higher pre-tax income.

Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020

Operating revenue decreased $75 million, or 14%, for the third quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $58 million and a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased prices of $11 million.

(Excess) cost of gas was a credit of $3 million for the third quarter of 2021 compared to an expense of $14 million for the third quarter of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices.

Operations and maintenance increased $6 million, or 5%, for the third quarter of 2021 compared to 2020, primarily due to a 2020 benefit associated with the probable abandonment of a significant portion of the Supply Header Project of $19 million, partially offset by the November 2020 disposition of Questar Pipeline Group of $13 million.

Depreciation and amortization decreased $12 million, or 13%, for the third quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.

Interest expense decreased$154 million, or 83%, for the third quarter of 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 $5 million and lower interest expense of $5 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.

Interest and dividend income decreased $10 million for the third quarter of 2021 compared to 2020, primarily due to interest income from DEI recognized in 2020 as a result of the GT&S Transaction.

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Other, net was an expense of $1 million for the third quarter of 2021 compared to income of $11 million for the third quarter of 2020. The change in other, net is primarily due to a decrease in non-service cost credits 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 $21 million for the third quarter of 2021 compared to a benefit of $10 million for the third quarter of 2020 and the effective tax rate was 12% for the third quarter of 2021 and (10)% for the third quarter of 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 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 $68 million for the third quarter of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.

First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020

Operating revenue decreased $218 million, or 14%, for the first nine months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $178 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $40 million, which is offset in operations and maintenance expense. This decrease in operating revenue was partially offset by an increase in regulated gas sales for operational and system balancing purposes primarily due to increased prices of $6 million.

(Excess) cost of gas was a credit of $13 million for the first nine months of 2021 compared to an expense of $23 million for the first nine months of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices of $48 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 $15 million.

Operations and maintenance decreased $560 million, or 61%, for the first nine months of 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of a significant portion of the Supply Header Project of $463 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $41 million and the November 2020 disposition of Questar Pipeline Group of $39 million.

Depreciation and amortization decreased $38 million, or 13%, for the first nine months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.

Property and other taxes increased$6 million, or 6%, for the first nine months of 2021 compared to 2020, primarily due to higher tax assessments.

Interest expense decreased $176 million, or 60%, for the first nine months of 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 $15 million and lower interest expense of $15 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.

Allowance for equity funds decreased $6 million, or 55%, for the first nine months of 2021 compared to 2020, 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 $67 million for the first nine months of 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 as a result of the GT&S Transaction.

Other, net decreased $38 million, or 97%, for the first nine months of 2021 compared to 2020, primarily due to a decrease in non-service cost credits 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 $70 million for the first nine months of 2021 compared to a benefit of $40 million for the first nine months of 2020 and the effective tax rate was 13% for the first nine months of 2021 and (48)% for the first nine months of 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 and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.
182

Net income attributable to noncontrolling interests increased $205 million for the first nine months of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.

Liquidity and Capital Resources

As of September 30, 2021, Eastern Energy Gas' total net liquidity was $490 million as follows (in millions):

Item 3.Cash and cash equivalentsQuantitative and Qualitative Disclosures About Market Risk$90 
Intercompany credit agreement(1)
400 
Total net liquidity$490 
Intercompany credit agreement:
Maturity date2022


(1)Refer to Note 13 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further discussion regarding Eastern Energy Gas' intercompany credit agreement.
Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 were $867 million and $1.3 billion, respectively. The change was primarily due to lower collections from affiliates, lower income tax receipts, lower distributions from equity method investments and the timing of payments of operating costs.

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 elected and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 were $(201) million and $2.9 billion, respectively. The change was primarily due to a decrease in repayments of loans by affiliates of $3.2 billion, partially offset by a decrease in loans to affiliates of $55 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2021 were $(607) million. Sources of cash totaled $256 million and consisted of proceeds from equity contributions, that primarily 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 $863 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $353 million and repayment of notes to affiliates of $9 million.

Net cash flows from financing activities for the nine-month period ended September 30, 2020 were $(4.2) billion. Sources of cash totaled $299 million and consisted of equity contributions. Uses of cash totaled $4.5 billion and consisted mainly of distributions to DEI of $4.2 billion, repayment of notes to affiliates of $253 million and repayments of short-term debt of $62 million.

Future Uses of Cash

Eastern Energy Gas 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 credit agreements, capital contributions 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 Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
183

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.

Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Natural gas transmission and storage$89 $15 $22 
Other169 276 454 
Total$258 $291 $476 

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 liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020.

184

Regulatory Matters

Eastern Energy Gas is subject to comprehensive regulation. Refer to Note 4 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for discussion regarding Eastern Energy Gas' 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 Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets and income taxes. For additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2020.
185

Item 3.Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016.2020. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2016.2020. Refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, Note 6 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q and Note 7 of the Notes to Consolidated Financial Statements of Nevada PowerPacifiCorp in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of September 30, 2017.2021.


Item 4.Controls and Procedures

Item 4.Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, 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 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 Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United 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 September 30, 20172021 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.




186

PART II


Item 1.Legal Proceedings

Not applicable.Item 1.Legal Proceedings


Item 1A.Risk Factors

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 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

Item 1A.Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016.2020.


Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.


Item 3.Defaults Upon Senior Securities

Item 3.Defaults Upon Senior Securities

Not applicable.


187
Item 4.Mine Safety Disclosures


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 Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.


Item 5.Other Information

Item 5.Other Information

Not applicable.


Item 6.Exhibits

Item 6.Exhibits

The following is a list of exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.



SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


188

Exhibit No.Description

BERKSHIRE HATHAWAY ENERGY
4.1
Fiscal Agency Agreement, dated as of April 9, 2021, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $550,000,000 in principal amount of the 3.40% Senior Notes due 2051 (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, 2021).
BERKSHIRE HATHAWAY ENERGY COMPANY
Date: November 3, 2017/s/ Patrick J. Goodman
Patrick J. Goodman
Executive Vice President and Chief Financial Officer
(principal financial and accounting officer)
PACIFICORP
Date: November 3, 2017/s/ Nikki L. Kobliha
Nikki L. Kobliha
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
MIDAMERICAN FUNDING, LLC
MIDAMERICAN ENERGY COMPANY
Date: November 3, 2017/s/ Thomas B. Specketer
Thomas B. Specketer
Vice President and Controller
of MidAmerican Funding, LLC
and Vice President and Chief Financial Officer
of MidAmerican Energy Company
(principal financial and accounting officer)
NEVADA POWER COMPANY
Date: November 3, 2017/s/ E. Kevin Bethel
E. Kevin Bethel
Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)
SIERRA PACIFIC POWER COMPANY
Date: November 3, 2017/s/ E. Kevin Bethel
E. Kevin Bethel
Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)


EXHIBIT INDEX

Exhibit No.Description

BERKSHIRE HATHAWAY ENERGY
10.1
$1,000,000,0003,500,000,000 Second Amended and Restated Credit Agreement, dated as of May 11, 2017,June 30, 2021, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, and TheMUFG Union Bank, of Tokyo-Mitsubishi UFJ, LTD.,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 June 30, 2017)2021).
15.1
Awareness Letter of Independent Registered Public Accounting Firm.
31.1
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 20022002..
31.2
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


PACIFICORP
15.2
Awareness Letter of Independent Registered Public Accounting Firm.
31.3
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.3
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.4
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
4.2
Thirty-Second Supplemental Indenture, dated as of July 1, 2021, to the 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 4.1 to the PacifiCorp Current Report on Form 8-K dated July 9, 2021).
10.2
$600,000,0001,200,000,000 Second Amended and Restated Credit Agreement dated as of June 30, 2017,2021, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, asInitial Lenders, JPMorganJP Morgan Chase Bank, N.A., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy CompanyPacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)2021).
95
Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.


MIDAMERICAN ENERGY
15.3
Awareness Letter of Independent Registered Public Accounting Firm.
31.5
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.6
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.5
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.6
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

189

Exhibit No.Description

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY
4.3
Tenth Supplemental Indenture, dated as of July 22, 2021, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated July 22, 2021).
10.34.4
Specimen of the 2.70% First Mortgage Bonds due 2052 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated July 22, 2021).
10.3
$900,000,0001,500,000,000 Second Amended and Restated Credit Agreement, dated as of June 30, 2017,2021, 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 10.3 to the Berkshire HathawayMidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)2021).




Exhibit No.Description

MIDAMERICAN FUNDING
31.7
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.8
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.7
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.8
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


NEVADA POWER
15.4
Awareness Letter of Independent Registered Public Accounting Firm.
31.9
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.10
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.9
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.10
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
4.110.4
Financing Agreement dated May 1, 2017 between Clark County, Nevada and Nevada Power Company (relating to Clark County, Nevada's $39,500,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2017) (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).
4.2
Financing Agreement dated May 1, 2017 between the Coconino County, Arizona Pollution Control Corporation and Nevada Power Company (relating to the Coconino County, Arizona Pollution Control Corporation's $53,000,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Projects) Series 2017A and 2017B) (incorporated by reference to Exhibit 4.2 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).
4.3
Officer’s Certificate establishing the terms of Nevada Power Company’s General and Refunding Mortgage Notes, Series AA (Nos. AA-1 and AA-2) (incorporated by reference to Exhibit 4.3 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).
10.4
$400,000,000 SecondFourth Amended and Restated Credit Agreement, dated as of June 30, 2017,2021, 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 10.4 to the Berkshire Hathaway EnergyNevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)2021).


SIERRA PACIFIC
31.11
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.12
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.11
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.12
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

190

Exhibit No.Description

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
10.5
$250,000,000 SecondFourth Amended and Restated Credit Agreement, dated as of June 30, 2017,2021, 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 10.510.5 to the Berkshire Hathaway Energy Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)2021).




EASTERN ENERGY GAS
Exhibit No.Description

ALL REGISTRANTS
31.13
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
10131.14
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.13
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.14
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS
4.5
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).
4.6
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., as trustee (incorporated by reference to Exhibit 4.6 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).
4.7
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).
4.8
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).
4.9
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).
4.10
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).
4.11
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).
191

Exhibit No.Description

ALL REGISTRANTS
101The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017,2021, 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.
104Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.

156
192

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BERKSHIRE HATHAWAY ENERGY COMPANY
Date: November 5, 2021/s/ Calvin D. Haack
Calvin D. Haack
Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)
PACIFICORP
Date: November 5, 2021/s/ Nikki L. Kobliha
Nikki L. Kobliha
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
MIDAMERICAN FUNDING, LLC
MIDAMERICAN ENERGY COMPANY
Date: November 5, 2021/s/ Thomas B. Specketer
Thomas B. Specketer
Vice President and Controller
of MidAmerican Funding, LLC and
Vice President and Chief Financial Officer
of MidAmerican Energy Company
(principal financial and accounting officer)
NEVADA POWER COMPANY
Date: November 5, 2021/s/ Michael E. Cole
Michael E. Cole
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
SIERRA PACIFIC POWER COMPANY
Date: November 5, 2021/s/ Michael E. Cole
Michael E. Cole
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
EASTERN ENERGY GAS HOLDINGS, LLC
Date: November 5, 2021/s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
193