UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended Sept. 30, 20212022
or
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☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-3034
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Xcel Energy Inc. |
(Exact nameName of registrantRegistrant as specifiedSpecified in its charter)Charter) |
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Minnesota | | | | 41-0448030 |
(State or other jurisdictionOther Jurisdiction of incorporationIncorporation or organization)Organization) | |
| | (I.R.S. Employer Identification No.) |
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414 Nicollet Mall | Minneapolis | Minnesota | | | | 55401 |
(Address of principal executive offices)
Principal Executive Offices) | | | | (Zip Code) |
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(612) | 330-5500 |
(Registrant’s telephone number, including area code) |
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N/A |
(Former name, former address and former fiscal year, if changed since last report)Telephone Number, Including Area Code) |
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
Common Stock, $2.50 par value | | XEL | | Nasdaq Stock Market LLC |
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. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 registrant was required to submit such files). ☒ Yes ☐ No
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.
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Large accelerated filer | ☒ | | Accelerated filer | ☐ | |
Non-accelerated filer | ☐ | | Smaller reporting company | ☐ | |
| | | Emerging growth company | ☐ | |
If an emerging growth company, indicate by check mark if the registrant has 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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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Class | | Outstanding at Oct. 26, 202125, 2022 |
Common Stock, $2.50 par value | | 538,675,570547,248,496 shares |
TABLE OF CONTENTS
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PART I | FINANCIAL INFORMATION | |
Item 1 — | | |
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Item 2 — | | |
Item 3 — | | |
Item 4 — | | |
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PART II | OTHER INFORMATION | |
Item 1 — | | |
Item 1A — | | |
Item 2 — | | |
Item 6 — | | |
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This Form 10-Q is filed by Xcel Energy Inc. Additional information is available onin various filings with the Securities and Exchange Commission.SEC. This report should be read in its entirety.
Definitions of Abbreviations
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Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) |
e prime | e prime inc. |
NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
NSP System | The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota |
NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
PSCo | Public Service Company of Colorado |
SPS | Southwestern Public Service Company |
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
WYCO | WYCO Development, LLC |
Xcel Energy | Xcel Energy Inc. and its subsidiaries |
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Federal and State Regulatory Agencies |
COEO | Colorado Energy Office |
CPUC | Colorado Public Utilities Commission |
D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |
DOC | Minnesota Department of Commerce |
EPA | United States Environmental Protection Agency |
ERCOT | Electric Reliability Council of Texas |
FERC | Federal Energy Regulatory Commission |
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MPUC | Minnesota Public Utilities Commission |
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NDPSC | North Dakota Public Service Commission |
NMPRC | New Mexico Public Regulation Commission |
NRC | Nuclear Regulatory Commission |
OAG | Minnesota Office of Attorney General |
PSCW | Public Service Commission of Wisconsin |
PUCT | Public Utility Commission of Texas |
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SEC | Securities and Exchange Commission |
UCA | Colorado Office of the Utility Consumer Advocate |
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Electric, Purchased Gas and Resource Adjustment Clauses |
DSMGCA | Demand side management |
FCA | Fuel clauseGas cost adjustment |
GUIC | Gas utility infrastructure cost rider |
PSIA | Pipeline System Integrity Adjustment |
RES | Renewable energy standard |
TCR | Transmission cost recovery adjustment |
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Other |
AFUDC | Allowance for funds used during construction |
ALJ | Administrative Law Judge |
ASCAMT | FASB Accounting Standards CodificationAlternative minimum tax |
ATM | At-the-market |
C&I | Commercial and Industrial |
CCR | Coal combustion residuals |
CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste |
CDD | Cooling degree-days |
CEO | Chief executive officer |
CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act |
CFO | Chief financial officer |
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COVID-19CORE | Novel coronavirusCORE Electric Cooperative |
CPCN | Certificate of Public Convenience and Necessity |
CSPV | Crystalline Silicon Photovoltaic |
CUB | Citizens Utility Board |
DRIP | Dividend Reinvestment and Stock Purchase Program |
EIP | Energy Impact Partners |
EPS | Earnings per share |
ETR | Effective tax rate |
FASB | Financial Accounting Standards Board |
FTR | Financial transmission right |
GAAP | United States generally accepted accounting principles |
GCA | Gas cost adjustment |
GE | General Electric Company |
HDD | Heating degree-days |
IPP | Independent power producing entity |
KEPCOIRA | Korea Electric Power CorporationInflation Reduction Act |
ITC | Investment Tax Credit |
JSC | Just Solar Coalition |
LLC | Limited liability company |
LP&L | Lubbock Power and Light |
MDL | Multi district litigation |
MEC | Mankato Energy Center |
MGP | Manufactured gas plant |
MISO | Midcontinent Independent System Operator, Inc. |
NAV | Net asset value |
NOL | Net operating loss |
NOPR | Notice of Proposed Rulemaking |
NOx | Nitrogen Oxides |
O&M | Operating and maintenance |
OATT | Open Access Transmission Tariff |
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PFAS | Per- and PolyFluoroAlkylPolyFluroroAlkyl Substances |
PIM | Performance Incentive Mechanism |
PPA | Power purchase agreement |
PTC | Production tax credit |
ROE | Return on equity |
RTO | Regional Transmission Organization |
SMMPA | Southern Minnesota Municipal Power Agency |
SPP | Southwest Power Pool, Inc. |
THI | Temperature-humidity index |
TOs | Transmission owners |
UCA | Colorado Office of the Utility Consumer Advocate |
VaR | Value at Risk |
VIEWACC | Variable interest entityWeighted average cost of capital |
XLI | Xcel Large Industrial Customers |
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Forward-Looking Statements |
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the 2021those relating to 2022 and 20222023 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 20202021 and subsequent filingfilings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic;pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; operational safety, including our nuclear generation facilities;facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs changes in regulation and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters, including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.
PART I — FINANCIAL INFORMATION
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ITEM 1 — FINANCIAL STATEMENTS |
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in millions, except per share data)
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Operating revenues | Operating revenues | | | | | | | | Operating revenues | | | | | | | |
Electric | Electric | $ | 3,176 | | | $ | 2,941 | | | $ | 8,643 | | | $ | 7,430 | | Electric | $ | 3,699 | | | $ | 3,176 | | | $ | 9,255 | | | $ | 8,643 | |
Natural gas | Natural gas | 268 | | | 219 | | | 1,364 | | | 1,082 | | Natural gas | 357 | | | 268 | | | 1,923 | | | 1,364 | |
Other | Other | 23 | | | 22 | | | 69 | | | 67 | | Other | 26 | | | 23 | | | 79 | | | 69 | |
Total operating revenues | Total operating revenues | 3,467 | | | 3,182 | | | 10,076 | | | 8,579 | | Total operating revenues | 4,082 | | | 3,467 | | | 11,257 | | | 10,076 | |
| Operating expenses | Operating expenses | | Operating expenses | |
Electric fuel and purchased power | Electric fuel and purchased power | 1,210 | | | 981 | | | 3,643 | | | 2,611 | | Electric fuel and purchased power | 1,497 | | | 1,210 | | | 3,772 | | | 3,643 | |
Cost of natural gas sold and transported | Cost of natural gas sold and transported | 86 | | | 54 | | | 603 | | | 425 | | Cost of natural gas sold and transported | 173 | | | 86 | | | 1,134 | | | 603 | |
Cost of sales — other | Cost of sales — other | 11 | | | 11 | | | 28 | | | 28 | | Cost of sales — other | 11 | | | 11 | | | 32 | | | 28 | |
Operating and maintenance expenses | 568 | | | 579 | | | 1,752 | | | 1,708 | | |
O&M expenses | | O&M expenses | 611 | | | 568 | | | 1,827 | | | 1,752 | |
Conservation and demand side management expenses | Conservation and demand side management expenses | 78 | | | 73 | | | 222 | | | 215 | | Conservation and demand side management expenses | 86 | | | 78 | | | 259 | | | 222 | |
Depreciation and amortization | Depreciation and amortization | 537 | | | 513 | | | 1,586 | | | 1,449 | | Depreciation and amortization | 607 | | | 537 | | | 1,807 | | | 1,586 | |
Taxes (other than income taxes) | Taxes (other than income taxes) | 152 | | | 158 | | | 472 | | | 453 | | Taxes (other than income taxes) | 173 | | | 152 | | | 523 | | | 472 | |
Total operating expenses | Total operating expenses | 2,642 | | | 2,369 | | | 8,306 | | | 6,889 | | Total operating expenses | 3,158 | | | 2,642 | | | 9,354 | | | 8,306 | |
| Operating income | Operating income | 825 | | | 813 | | | 1,770 | | | 1,690 | | Operating income | 924 | | | 825 | | | 1,903 | | | 1,770 | |
| Other (expense) income, net | Other (expense) income, net | (3) | | | 1 | | | 5 | | | (6) | | Other (expense) income, net | (15) | | | (3) | | | (20) | | | 5 | |
Earnings from equity method investments | Earnings from equity method investments | 13 | | | 12 | | | 47 | | | 29 | | Earnings from equity method investments | 1 | | | 13 | | | 27 | | | 47 | |
Allowance for funds used during construction — equity | Allowance for funds used during construction — equity | 21 | | | 30 | | | 53 | | | 91 | | Allowance for funds used during construction — equity | 20 | | | 21 | | | 53 | | | 53 | |
| Interest charges and financing costs | Interest charges and financing costs | | Interest charges and financing costs | |
Interest charges — includes other financing costs of $7, $7, $22 and $21, respectively | 211 | | | 221 | | | 628 | | | 628 | | |
Interest charges — includes other financing costs of $8, $7, $24 and $22, respectively | | Interest charges — includes other financing costs of $8, $7, $24 and $22, respectively | 244 | | | 211 | | | 705 | | | 628 | |
Allowance for funds used during construction — debt | Allowance for funds used during construction — debt | (7) | | | (11) | | | (18) | | | (33) | | Allowance for funds used during construction — debt | (7) | | | (7) | | | (19) | | | (18) | |
Total interest charges and financing costs | Total interest charges and financing costs | 204 | | | 210 | | | 610 | | | 595 | | Total interest charges and financing costs | 237 | | | 204 | | | 686 | | | 610 | |
| Income before income taxes | Income before income taxes | 652 | | | 646 | | | 1,265 | | | 1,209 | | Income before income taxes | 693 | | | 652 | | | 1,277 | | | 1,265 | |
Income tax expense (benefit) | Income tax expense (benefit) | 43 | | | 43 | | | (17) | | | 24 | | Income tax expense (benefit) | 44 | | | 43 | | | (80) | | | (17) | |
Net income | Net income | $ | 609 | | | $ | 603 | | | $ | 1,282 | | | $ | 1,185 | | Net income | $ | 649 | | | $ | 609 | | | $ | 1,357 | | | $ | 1,282 | |
| Weighted average common shares outstanding: | Weighted average common shares outstanding: | | Weighted average common shares outstanding: | |
Basic | Basic | 539 | | | 526 | | | 539 | | | 526 | | Basic | 548 | | | 539 | | | 546 | | | 539 | |
Diluted | Diluted | 539 | | | 528 | | | 539 | | | 527 | | Diluted | 548 | | | 539 | | | 546 | | | 539 | |
| Earnings per average common share: | Earnings per average common share: | | Earnings per average common share: | |
Basic | Basic | $ | 1.13 | | | $ | 1.15 | | | $ | 2.38 | | | $ | 2.25 | | Basic | $ | 1.19 | | | $ | 1.13 | | | $ | 2.48 | | | $ | 2.38 | |
Diluted | Diluted | 1.13 | | | 1.14 | | | 2.38 | | | 2.25 | | Diluted | 1.18 | | | 1.13 | | | 2.48 | | | 2.38 | |
| See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in millions)
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Net income | Net income | $ | 609 | | | $ | 603 | | | $ | 1,282 | | | $ | 1,185 | | Net income | $ | 649 | | | $ | 609 | | | $ | 1,357 | | | $ | 1,282 | |
Other comprehensive income (loss) | | |
Other comprehensive income | | Other comprehensive income | |
Pension and retiree medical benefits: | Pension and retiree medical benefits: | | | Pension and retiree medical benefits: | | |
| Reclassifications of loss to net income, net of tax of $1, $—, $2 and $1, respectively | 4 | | | 1 | | | 5 | | | 4 | | |
Net pension and retiree medical losses arising during the period, net of tax of $4, $—, $4 and $—, respectively | | Net pension and retiree medical losses arising during the period, net of tax of $4, $—, $4 and $—, respectively | 10 | | | — | | | 11 | | | — | |
Reclassifications of loss to net income, net of tax of $—, $1, $1 and $2, respectively | | Reclassifications of loss to net income, net of tax of $—, $1, $1 and $2, respectively | 1 | | | 4 | | | 2 | | | 5 | |
Derivative instruments: | Derivative instruments: | | | Derivative instruments: | |
Net fair value increase (decrease), net of tax of $1, $—, $1 and $(3), respectively | 3 | | | — | | | 4 | | | (10) | | |
Net fair value increase, net of tax of $—, $1, $6 and $1, respectively | | Net fair value increase, net of tax of $—, $1, $6 and $1, respectively | — | | | 3 | | | 15 | | | 4 | |
Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively | Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively | 2 | | | 1 | | | 6 | | | 4 | | Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively | 1 | | | 2 | | | 4 | | | 6 | |
| Total other comprehensive income (loss) | 9 | | | 2 | | | 15 | | | (2) | | |
Total other comprehensive income | | Total other comprehensive income | 12 | | | 9 | | | 32 | | | 15 | |
Total comprehensive income | Total comprehensive income | $ | 618 | | | $ | 605 | | | $ | 1,297 | | | $ | 1,183 | | Total comprehensive income | $ | 661 | | | $ | 618 | | | $ | 1,389 | | | $ | 1,297 | |
| See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)
| | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 | | 2020 | | 2022 | | 2021 |
Operating activities | Operating activities | | | | Operating activities | | | |
Net income | Net income | $ | 1,282 | | | $ | 1,185 | | Net income | $ | 1,357 | | | $ | 1,282 | |
Adjustments to reconcile net income to cash provided by operating activities: | Adjustments to reconcile net income to cash provided by operating activities: | | Adjustments to reconcile net income to cash provided by operating activities: | |
Depreciation and amortization | Depreciation and amortization | 1,597 | | | 1,459 | | Depreciation and amortization | 1,821 | | | 1,597 | |
Nuclear fuel amortization | Nuclear fuel amortization | 86 | | | 94 | | Nuclear fuel amortization | 91 | | | 86 | |
Deferred income taxes | Deferred income taxes | (9) | | | 45 | | Deferred income taxes | (85) | | | (9) | |
Allowance for equity funds used during construction | Allowance for equity funds used during construction | (53) | | | (91) | | Allowance for equity funds used during construction | (53) | | | (53) | |
Earnings from equity method investments | Earnings from equity method investments | (47) | | | (29) | | Earnings from equity method investments | (27) | | | (47) | |
Dividends from equity method investments | Dividends from equity method investments | 31 | | | 32 | | Dividends from equity method investments | 30 | | | 31 | |
Provision for bad debts | Provision for bad debts | 53 | | | 39 | | Provision for bad debts | 41 | | | 53 | |
Share-based compensation expense | Share-based compensation expense | 20 | | | 60 | | Share-based compensation expense | 19 | | | 20 | |
Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
Accounts receivable | Accounts receivable | (152) | | | (108) | | Accounts receivable | (221) | | | (152) | |
Accrued unbilled revenues | Accrued unbilled revenues | 58 | | | 124 | | Accrued unbilled revenues | 69 | | | 58 | |
Inventories | Inventories | (82) | | | (37) | | Inventories | (272) | | | (82) | |
Other current assets | Other current assets | 8 | | | (68) | | Other current assets | 13 | | | 8 | |
Accounts payable | Accounts payable | 61 | | | (97) | | Accounts payable | 152 | | | 61 | |
Net regulatory assets and liabilities | Net regulatory assets and liabilities | (997) | | | (139) | | Net regulatory assets and liabilities | 239 | | | (997) | |
Other current liabilities | Other current liabilities | (22) | | | (54) | | Other current liabilities | 51 | | | (22) | |
Pension and other employee benefit obligations | Pension and other employee benefit obligations | (131) | | | (138) | | Pension and other employee benefit obligations | (59) | | | (131) | |
Other, net | Other, net | (124) | | | (103) | | Other, net | 1 | | | (124) | |
Net cash provided by operating activities | Net cash provided by operating activities | 1,579 | | | 2,174 | | Net cash provided by operating activities | 3,167 | | | 1,579 | |
| Investing activities | Investing activities | | Investing activities | |
Capital/construction expenditures | Capital/construction expenditures | (3,032) | | | (3,681) | | Capital/construction expenditures | (3,325) | | | (3,032) | |
Sale of MEC | — | | | 684 | | |
Purchase of investment securities | Purchase of investment securities | (540) | | | (1,275) | | Purchase of investment securities | (1,055) | | | (540) | |
Proceeds from the sale of investment securities | Proceeds from the sale of investment securities | 531 | | | 1,260 | | Proceeds from the sale of investment securities | 1,029 | | | 531 | |
Other, net | Other, net | (24) | | | (9) | | Other, net | 30 | | | (24) | |
Net cash used in investing activities | Net cash used in investing activities | (3,065) | | | (3,021) | | Net cash used in investing activities | (3,321) | | | (3,065) | |
| Financing activities | Financing activities | | Financing activities | |
Proceeds from (repayments of) short-term borrowings, net | 1,163 | | | (95) | | |
(Repayments of) proceeds from short-term borrowings, net | | (Repayments of) proceeds from short-term borrowings, net | (847) | | | 1,163 | |
Proceeds from issuances of long-term debt | Proceeds from issuances of long-term debt | 1,920 | | | 2,940 | | Proceeds from issuances of long-term debt | 2,164 | | | 1,920 | |
Repayments of long-term debt, including reacquisition premiums | Repayments of long-term debt, including reacquisition premiums | (399) | | | (701) | | Repayments of long-term debt, including reacquisition premiums | (600) | | | (399) | |
Proceeds from issuance of common stock | Proceeds from issuance of common stock | 13 | | | 5 | | Proceeds from issuance of common stock | 156 | | | 13 | |
Dividends paid | Dividends paid | (698) | | | (638) | | Dividends paid | (754) | | | (698) | |
Other, net | Other, net | (11) | | | (27) | | Other, net | (14) | | | (11) | |
Net cash provided by financing activities | Net cash provided by financing activities | 1,988 | | | 1,484 | | Net cash provided by financing activities | 105 | | | 1,988 | |
| Net change in cash, cash equivalents and restricted cash | Net change in cash, cash equivalents and restricted cash | 502 | | | 637 | | Net change in cash, cash equivalents and restricted cash | (49) | | | 502 | |
Cash, cash equivalents and restricted cash at beginning of period | Cash, cash equivalents and restricted cash at beginning of period | 129 | | | 248 | | Cash, cash equivalents and restricted cash at beginning of period | 166 | | | 129 | |
Cash, cash equivalents and restricted cash at end of period | Cash, cash equivalents and restricted cash at end of period | $ | 631 | | | $ | 885 | | Cash, cash equivalents and restricted cash at end of period | $ | 117 | | | $ | 631 | |
| Supplemental disclosure of cash flow information: | Supplemental disclosure of cash flow information: | | Supplemental disclosure of cash flow information: | |
Cash paid for interest (net of amounts capitalized) | Cash paid for interest (net of amounts capitalized) | $ | (592) | | | $ | (582) | | Cash paid for interest (net of amounts capitalized) | $ | (628) | | | $ | (592) | |
Cash paid for income taxes, net | Cash paid for income taxes, net | (6) | | | (17) | | Cash paid for income taxes, net | (16) | | | (6) | |
| Supplemental disclosure of non-cash investing and financing transactions: | Supplemental disclosure of non-cash investing and financing transactions: | | Supplemental disclosure of non-cash investing and financing transactions: | |
Accrued property, plant and equipment additions | Accrued property, plant and equipment additions | $ | 476 | | | $ | 933 | | Accrued property, plant and equipment additions | $ | 393 | | | $ | 476 | |
Inventory transfers to property, plant and equipment | Inventory transfers to property, plant and equipment | 87 | | | 250 | | Inventory transfers to property, plant and equipment | 34 | | | 87 | |
Operating lease right-of-use assets | Operating lease right-of-use assets | 4 | | | 361 | | Operating lease right-of-use assets | 17 | | | 4 | |
Allowance for equity funds used during construction | Allowance for equity funds used during construction | 53 | | | 91 | | Allowance for equity funds used during construction | 53 | | | 53 | |
Issuance of common stock for reinvested dividends and/or equity awards | Issuance of common stock for reinvested dividends and/or equity awards | 26 | | | 51 | | Issuance of common stock for reinvested dividends and/or equity awards | 40 | | | 26 | |
| See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in millions, except share and per share data)
| | | Sept. 30, 2021 | | Dec. 31, 2020 | | Sept. 30, 2022 | | Dec. 31, 2021 |
Assets | Assets | | | | Assets | | | |
Current assets | Current assets | | Current assets | |
Cash and cash equivalents | Cash and cash equivalents | $ | 631 | | | $ | 129 | | Cash and cash equivalents | $ | 117 | | | $ | 166 | |
Accounts receivable, net | Accounts receivable, net | 1,022 | | | 916 | | Accounts receivable, net | 1,196 | | | 1,018 | |
Accrued unbilled revenues | Accrued unbilled revenues | 656 | | | 714 | | Accrued unbilled revenues | 793 | | | 862 | |
Inventories | Inventories | 587 | | | 535 | | Inventories | 870 | | | 631 | |
Regulatory assets | Regulatory assets | 1,073 | | | 640 | | Regulatory assets | 1,275 | | | 1,106 | |
Derivative instruments | Derivative instruments | 228 | | | 49 | | Derivative instruments | 456 | | | 123 | |
Prepaid taxes | Prepaid taxes | 55 | | | 42 | | Prepaid taxes | 54 | | | 44 | |
Prepayments and other | Prepayments and other | 235 | | | 250 | | Prepayments and other | 329 | | | 289 | |
Total current assets | Total current assets | 4,487 | | | 3,275 | | Total current assets | 5,090 | | | 4,239 | |
| Property, plant and equipment, net | Property, plant and equipment, net | 44,730 | | | 42,950 | | Property, plant and equipment, net | 47,287 | | | 45,457 | |
| Other assets | Other assets | | Other assets | |
Nuclear decommissioning fund and other investments | Nuclear decommissioning fund and other investments | 3,446 | | | 3,096 | | Nuclear decommissioning fund and other investments | 3,083 | | | 3,628 | |
Regulatory assets | Regulatory assets | 3,101 | | | 2,737 | | Regulatory assets | 2,850 | | | 2,738 | |
Derivative instruments | Derivative instruments | 72 | | | 30 | | Derivative instruments | 90 | | | 67 | |
Operating lease right-of-use assets | Operating lease right-of-use assets | 1,342 | | | 1,490 | | Operating lease right-of-use assets | 1,155 | | | 1,291 | |
Other | Other | 339 | | | 379 | | Other | 420 | | | 431 | |
Total other assets | Total other assets | 8,300 | | | 7,732 | | Total other assets | 7,598 | | | 8,155 | |
Total assets | Total assets | $ | 57,517 | | | $ | 53,957 | | Total assets | $ | 59,975 | | | $ | 57,851 | |
| Liabilities and Equity | Liabilities and Equity | | Liabilities and Equity | |
Current liabilities | Current liabilities | | Current liabilities | |
Current portion of long-term debt | Current portion of long-term debt | $ | 621 | | | $ | 421 | | Current portion of long-term debt | $ | 651 | | | $ | 601 | |
Short-term debt | Short-term debt | 1,747 | | | 584 | | Short-term debt | 158 | | | 1,005 | |
Accounts payable | Accounts payable | 1,319 | | | 1,237 | | Accounts payable | 1,586 | | | 1,409 | |
Regulatory liabilities | Regulatory liabilities | 338 | | | 311 | | Regulatory liabilities | 596 | | | 271 | |
Taxes accrued | Taxes accrued | 553 | | | 578 | | Taxes accrued | 545 | | | 569 | |
Accrued interest | Accrued interest | 206 | | | 203 | | Accrued interest | 244 | | | 209 | |
Dividends payable | Dividends payable | 246 | | | 231 | | Dividends payable | 267 | | | 249 | |
Derivative instruments | Derivative instruments | 76 | | | 53 | | Derivative instruments | 100 | | | 69 | |
Operating lease liabilities | Operating lease liabilities | 218 | | | 214 | | Operating lease liabilities | 211 | | | 205 | |
Other | Other | 440 | | | 407 | | Other | 545 | | | 459 | |
Total current liabilities | Total current liabilities | 5,764 | | | 4,239 | | Total current liabilities | 4,903 | | | 5,046 | |
| Deferred credits and other liabilities | Deferred credits and other liabilities | | Deferred credits and other liabilities | |
Deferred income taxes | Deferred income taxes | 4,913 | | | 4,746 | | Deferred income taxes | 4,762 | | | 4,894 | |
| Deferred investment tax credits | | Deferred investment tax credits | 50 | | | 53 | |
Regulatory liabilities | Regulatory liabilities | 5,389 | | | 5,302 | | Regulatory liabilities | 5,567 | | | 5,405 | |
Asset retirement obligations | Asset retirement obligations | 3,094 | | | 2,884 | | Asset retirement obligations | 3,296 | | | 3,151 | |
Derivative instruments | Derivative instruments | 99 | | | 131 | | Derivative instruments | 114 | | | 105 | |
Customer advances | Customer advances | 199 | | | 197 | | Customer advances | 187 | | | 196 | |
Pension and employee benefit obligations | Pension and employee benefit obligations | 515 | | | 666 | | Pension and employee benefit obligations | 255 | | | 306 | |
Operating lease liabilities | Operating lease liabilities | 1,187 | | | 1,344 | | Operating lease liabilities | 997 | | | 1,146 | |
Other | Other | 207 | | | 228 | | Other | 151 | | | 158 | |
Total deferred credits and other liabilities | Total deferred credits and other liabilities | 15,603 | | | 15,498 | | Total deferred credits and other liabilities | 15,379 | | | 15,414 | |
| Commitments and contingencies | Commitments and contingencies | 0 | | 0 | Commitments and contingencies | |
Capitalization | Capitalization | | Capitalization | |
Long-term debt | Long-term debt | 20,979 | | | 19,645 | | Long-term debt | 23,309 | | | 21,779 | |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 538,458,952 and 537,438,394 shares outstanding at Sept. 30, 2021 and Dec. 31, 2020, respectively | 1,346 | | | 1,344 | | |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 547,006,076 and 544,025,269 shares outstanding at Sept. 30, 2022 and Dec. 31, 2021, respectively | | Common stock — 1,000,000,000 shares authorized of $2.50 par value; 547,006,076 and 544,025,269 shares outstanding at Sept. 30, 2022 and Dec. 31, 2021, respectively | 1,368 | | | 1,360 | |
Additional paid in capital | Additional paid in capital | 7,443 | | | 7,404 | | Additional paid in capital | 7,979 | | | 7,803 | |
Retained earnings | Retained earnings | 6,508 | | | 5,968 | | Retained earnings | 7,128 | | | 6,572 | |
Accumulated other comprehensive loss | Accumulated other comprehensive loss | (126) | | | (141) | | Accumulated other comprehensive loss | (91) | | | (123) | |
Total common stockholders’ equity | Total common stockholders’ equity | 15,171 | | | 14,575 | | Total common stockholders’ equity | 16,384 | | | 15,612 | |
Total liabilities and equity | Total liabilities and equity | $ | 57,517 | | | $ | 53,957 | | Total liabilities and equity | $ | 59,975 | | | $ | 57,851 | |
| See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in millions, except per share data; shares in actual amounts)
| | | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders' Equity | | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders' Equity |
| | Shares | | Par Value | | Additional Paid In Capital | | | Shares | | Par Value | | Additional Paid In Capital | |
Three Months Ended Sept. 30, 2021 and 2020 | | | | | | | | | | | | |
Balance at June 30, 2020 | 525,204,978 | | | $ | 1,313 | | | $ | 6,679 | | | $ | 5,538 | | | $ | (145) | | | $ | 13,385 | | |
Net income | | 603 | | | 603 | | |
Other comprehensive income | | 2 | | | 2 | | |
Dividends declared on common stock ($0.43 per share) | | (226) | | | (226) | | |
Issuances of common stock | 302,321 | | | 1 | | | 9 | | | 10 | | |
Repurchase of common stock | (54,475) | | | — | | | (4) | | | (4) | | |
Share-based compensation | | 10 | | | (3) | | | 7 | | |
Balance at Sept. 30, 2020 | 525,452,824 | | | $ | 1,314 | | | $ | 6,694 | | | $ | 5,912 | | | $ | (143) | | | $ | 13,777 | | |
| Three Months Ended Sept. 30, 2022 and 2021 | | Three Months Ended Sept. 30, 2022 and 2021 | | | | | | | | | | | |
Balance at June 30, 2021 | Balance at June 30, 2021 | 538,305,927 | | | $ | 1,346 | | | $ | 7,435 | | | $ | 6,146 | | | $ | (135) | | | $ | 14,792 | | Balance at June 30, 2021 | 538,305,927 | | | $ | 1,346 | | | $ | 7,435 | | | $ | 6,146 | | | $ | (135) | | | $ | 14,792 | |
Net income | Net income | | 609 | | | 609 | | Net income | | 609 | | | 609 | |
Other comprehensive income | Other comprehensive income | | 9 | | | 9 | | Other comprehensive income | | 9 | | | 9 | |
Dividends declared on common stock ($0.4575 per share) | Dividends declared on common stock ($0.4575 per share) | | (247) | | | (247) | | Dividends declared on common stock ($0.4575 per share) | | (247) | | | (247) | |
Issuances of common stock | Issuances of common stock | 153,025 | | | — | | | 10 | | | 10 | | Issuances of common stock | 153,025 | | | — | | | 10 | | | 10 | |
| Share-based compensation | Share-based compensation | | (2) | | | — | | | (2) | | Share-based compensation | | (2) | | | (2) | |
Balance at Sept. 30, 2021 | Balance at Sept. 30, 2021 | 538,458,952 | | | $ | 1,346 | | | $ | 7,443 | | | $ | 6,508 | | | $ | (126) | | | $ | 15,171 | | Balance at Sept. 30, 2021 | 538,458,952 | | | $ | 1,346 | | | $ | 7,443 | | | $ | 6,508 | | | $ | (126) | | | $ | 15,171 | |
| Balance at June 30, 2022 | | Balance at June 30, 2022 | 546,807,793 | | | $ | 1,367 | | | $ | 7,960 | | | $ | 6,747 | | | $ | (103) | | | $ | 15,971 | |
Net income | | Net income | | 649 | | | 649 | |
Other comprehensive income | | Other comprehensive income | | 12 | | | 12 | |
Dividends declared on common stock ($0.4875 per share) | | Dividends declared on common stock ($0.4875 per share) | | (267) | | | (267) | |
Issuances of common stock | | Issuances of common stock | 198,283 | | | 1 | | | 13 | | | 14 | |
| Share-based compensation | | Share-based compensation | | 6 | | | (1) | | | 5 | |
Balance at Sept. 30, 2022 | | Balance at Sept. 30, 2022 | 547,006,076 | | | $ | 1,368 | | | $ | 7,979 | | | $ | 7,128 | | | $ | (91) | | | $ | 16,384 | |
| | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders' Equity | | | | | | | | | | | | |
| | Shares | | Par Value | | Additional Paid In Capital | | | Common Stock Issued | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders' Equity |
Nine Months Ended Sept. 30, 2021 and 2020 | | | | | | | | | | | | |
Balance at Dec. 31, 2019 | 524,539,000 | | | $ | 1,311 | | | $ | 6,656 | | | $ | 5,413 | | | $ | (141) | | | $ | 13,239 | | |
| | | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Common Stockholders' Equity |
Nine Months Ended Sept. 30, 2022 and 2021 | | Nine Months Ended Sept. 30, 2022 and 2021 | | | | | | |
Balance at Dec. 31, 2020 | | Balance at Dec. 31, 2020 | 537,438,394 | | | $ | 1,344 | | | $ | 7,404 | | | $ | 5,968 | | | $ | (141) | | | $ | 14,575 | |
Net income | Net income | | 1,185 | | | 1,185 | | Net income | | 1,282 | | | 1,282 | |
Other comprehensive loss | Other comprehensive loss | | (2) | | | (2) | | Other comprehensive loss | | 15 | | | 15 | |
Dividends declared on common stock ($1.29 per share) | | (679) | | | (679) | | |
Issuances of common stock | 968,299 | | | 3 | | | 30 | | | 33 | | |
Repurchase of common stock | (54,475) | | | — | | | (4) | | | (4) | | |
Share-based compensation | | 12 | | | (5) | | | 7 | | |
Adoption of ASC Topic 326 | | (2) | | | (2) | | |
Balance at Sept. 30, 2020 | 525,452,824 | | | $ | 1,314 | | | $ | 6,694 | | | $ | 5,912 | | | $ | (143) | | | $ | 13,777 | | |
| Balance at Dec. 31, 2020 | 537,438,394 | | | $ | 1,344 | | | $ | 7,404 | | | $ | 5,968 | | | $ | (141) | | | $ | 14,575 | | |
Net income | | 1,282 | | | 1,282 | | |
Other comprehensive income | | 15 | | | 15 | | |
Dividends declared on common stock ($1.373 per share) | Dividends declared on common stock ($1.373 per share) | | (739) | | | (739) | | Dividends declared on common stock ($1.373 per share) | | (739) | | | (739) | |
Issuances of common stock | Issuances of common stock | 1,020,558 | | | 2 | | | 38 | | | 40 | | Issuances of common stock | 1,020,558 | | | 2 | | | 38 | | | 40 | |
| Share-based compensation | Share-based compensation | | 1 | | | (3) | | | (2) | | Share-based compensation | | 1 | | | (3) | | | (2) | |
| Balance at Sept. 30, 2021 | Balance at Sept. 30, 2021 | 538,458,952 | | | $ | 1,346 | | | $ | 7,443 | | | $ | 6,508 | | | $ | (126) | | | $ | 15,171 | | Balance at Sept. 30, 2021 | 538,458,952 | | | $ | 1,346 | | | $ | 7,443 | | | $ | 6,508 | | | $ | (126) | | | $ | 15,171 | |
| Balance at Dec. 31, 2021 | | Balance at Dec. 31, 2021 | 544,025,269 | | | $ | 1,360 | | | $ | 7,803 | | | $ | 6,572 | | | $ | (123) | | | $ | 15,612 | |
Net income | | Net income | | 1,357 | | | 1,357 | |
Other comprehensive income | | Other comprehensive income | | 32 | | | 32 | |
Dividends declared on common stock ($1.463 per share) | | Dividends declared on common stock ($1.463 per share) | | (798) | | | (798) | |
Issuances of common stock | | Issuances of common stock | 2,980,807 | | | 8 | | | 177 | | | 185 | |
| Share-based compensation | | Share-based compensation | | (1) | | | (3) | | | (4) | |
Balance at Sept. 30, 2022 | | Balance at Sept. 30, 2022 | 547,006,076 | | | $ | 1,368 | | | $ | 7,979 | | | $ | 7,128 | | | $ | (91) | | | $ | 16,384 | |
| See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements | See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of Sept. 30, 20212022 and Dec. 31, 2020;2021; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 20212022 and 2020;2021; and Xcel Energy’s cash flows for the nine months ended Sept. 30, 20212022 and 2020.2021.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2021,2022, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 20202021 balance sheet information has been derived from the audited 20202021 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2020.2021. Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2020,2021, filed with the SEC on Feb. 17, 2021.23, 2022. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.
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1. Summary of Significant Accounting Policies |
The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 20202021 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. Subsequent Event
On Oct. 25, 2021, PSCo filed a comprehensive settlement with the CPUC Staff and the COEO, which proposes to address four outstanding regulatory items, including recovery of fuel costs related to Winter Storm Uri, disputed revenue associated with the 2020 electric decoupling pilot program year, replacement power costs associated with an extended outage at Comanche Unit 3 during 2020 and deferred customer bad debt balances associated with COVID-19. The UCA has not signed the settlement. A hearing and a CPUC decision on the settlement is expected in the first quarter of 2022.
Key terms of the proposed settlement:
•PSCo would fully recover Winter Storm Uri deferred net natural gas, fuel and purchased energy costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with 0 carrying charges through a rider mechanism. Recovery would commence Jan. 1, 2022 for electric costs and April 1, 2022 for natural gas costs.
•PSCo will refund electric customers $41 million (previously deferred) related to the 2020 electric decoupling pilot program.
•PSCo agreed to forego recovery of $14 million for replacement power costs due to an extended outage at Comanche Unit 3 during 2020.
•PSCo also agreed to not seek recovery of COVID-19 related bad debt expense, previously deferred as a regulatory asset, and recorded an additional $11 million of incremental bad debt expense for the period ended Sept. 30, 2021.
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2. Accounting Pronouncements |
Credit Losses— In 2016,As of Sept. 30, 2022, there was no material impact from the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.
Xcel Energy implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020,recent adoption of ASC Topic 326 did not have a significantnew accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy’s consolidated financial statements.
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3. Selected Balance Sheet Data |
| (Millions of Dollars) | (Millions of Dollars) | | Sept. 30, 2021 | | Dec. 31, 2020 | (Millions of Dollars) | | Sept. 30, 2022 | | Dec. 31, 2021 |
Accounts receivable, net | Accounts receivable, net | | | | | Accounts receivable, net | | | | |
Accounts receivable | Accounts receivable | | $ | 1,119 | | | $ | 995 | | Accounts receivable | | $ | 1,308 | | | $ | 1,124 | |
Less allowance for bad debts | Less allowance for bad debts | | (97) | | | (79) | | Less allowance for bad debts | | (112) | | | (106) | |
Accounts receivable, net | Accounts receivable, net | | $ | 1,022 | | | $ | 916 | | Accounts receivable, net | | $ | 1,196 | | | $ | 1,018 | |
| (Millions of Dollars) | (Millions of Dollars) | | Sept. 30, 2021 | | Dec. 31, 2020 | (Millions of Dollars) | | Sept. 30, 2022 | | Dec. 31, 2021 |
Inventories | Inventories | | | | | Inventories | | | | |
Materials and supplies | Materials and supplies | | $ | 283 | | | $ | 275 | | Materials and supplies | | $ | 321 | | | $ | 289 | |
Fuel | Fuel | | 155 | | | 176 | | Fuel | | 234 | | | 182 | |
Natural gas | Natural gas | | 149 | | | 84 | | Natural gas | | 315 | | | 160 | |
Total inventories | Total inventories | | $ | 587 | | | $ | 535 | | Total inventories | | $ | 870 | | | $ | 631 | |
| (Millions of Dollars) | (Millions of Dollars) | | Sept. 30, 2021 | | Dec. 31, 2020 | (Millions of Dollars) | | Sept. 30, 2022 | | Dec. 31, 2021 |
Property, plant and equipment, net | Property, plant and equipment, net | | | | | Property, plant and equipment, net | | | | |
Electric plant | Electric plant | | $ | 49,293 | | | $ | 47,104 | | Electric plant | | $ | 48,959 | | | $ | 48,680 | |
Natural gas plant | Natural gas plant | | 7,443 | | | 7,135 | | Natural gas plant | | 8,199 | | | 7,758 | |
Common and other property | Common and other property | | 2,519 | | | 2,503 | | Common and other property | | 2,824 | | | 2,602 | |
Plant to be retired (a) | Plant to be retired (a) | | 603 | | | 677 | | Plant to be retired (a) | | 2,258 | | | 1,200 | |
Construction work in progress | Construction work in progress | | 2,263 | | | 1,877 | | Construction work in progress | | 2,445 | | | 1,969 | |
Total property, plant and equipment | Total property, plant and equipment | | 62,121 | | | 59,296 | | Total property, plant and equipment | | 64,685 | | | 62,209 | |
Less accumulated depreciation | Less accumulated depreciation | | (17,711) | | | (16,657) | | Less accumulated depreciation | | (17,639) | | | (17,060) | |
Nuclear fuel | Nuclear fuel | | 3,065 | | | 2,970 | | Nuclear fuel | | 3,105 | | | 3,081 | |
Less accumulated amortization | Less accumulated amortization | | (2,745) | | | (2,659) | | Less accumulated amortization | | (2,864) | | | (2,773) | |
Property, plant and equipment, net | Property, plant and equipment, net | | $ | 44,730 | | | $ | 42,950 | | Property, plant and equipment, net | | $ | 47,287 | | | $ | 45,457 | |
(a)Includes regulator-approved retirementsAmounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Following the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Sept. 30, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and jointly owned Craig Unit 1 for PSCo and Sherco Units 1 and 2 for NSP-Minnesota. Also includes SPS’ expected retirementcoal generation assets at Pawnee pending facility gas conversion. Amounts are presented net of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.accumulated depreciation.
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4. Borrowings and Other Financing Instruments |
Short-Term Borrowings
Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding for Xcel Energy:
| (Amounts in Millions, Except Interest Rates) | (Amounts in Millions, Except Interest Rates) | | Three Months Ended Sept. 30, 2021 | | Year Ended Dec. 31, 2020 | (Amounts in Millions, Except Interest Rates) | | Three Months Ended Sept. 30, 2022 | | Year Ended Dec. 31, 2021 |
Borrowing limit | Borrowing limit | | $ | 4,300 | | | $ | 3,100 | | Borrowing limit | | $ | 3,550 | | | $ | 3,100 | |
Amount outstanding at period end | Amount outstanding at period end | | 1,747 | | | 584 | | Amount outstanding at period end | | 158 | | | 1,005 | |
Average amount outstanding | Average amount outstanding | | 1,742 | | | 1,126 | | Average amount outstanding | | 187 | | | 1,399 | |
Maximum amount outstanding | Maximum amount outstanding | | 1,857 | | | 2,080 | | Maximum amount outstanding | | 329 | | | 2,054 | |
Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.57 | % | | 1.45 | % | Weighted average interest rate, computed on a daily basis | | 2.51 | % | | 0.57 | % |
Weighted average interest rate at period end | Weighted average interest rate at period end | | 0.56 | | | 0.23 | | Weighted average interest rate at period end | | 3.40 | | | 0.31 | |
Letters of Credit — Xcel Energy Inc. and its utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain obligations. There were $19$39 million and $20$19 million of letters of credit outstanding under the credit facilities at Sept. 30, 20212022 and Dec. 31, 2020,2021, respectively. Amounts approximate their fair value and are subject to fees.
Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities at least equal to the amount of commercial paper borrowing limits and cannot issue commercial paper exceeding available credit facility capacity. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreements —In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $3.55 billion. The amended credit agreements have substantially the same terms and conditions as the prior agreements, with the following changes:
•Maturities were extended from June 2024 to September 2027.
•Borrowing limit for Xcel Energy Inc. was increased from $1.25 billion to $1.5 billion.
•Borrowing limit for NSP-Minnesota was increased from $500 million to $700 million.
As of Sept. 30, 2021,2022, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:
| (Millions of Dollars) | (Millions of Dollars) | | Credit Facility (a) | | Drawn (b) | | Available | (Millions of Dollars) | | Credit Facility (a) | | Drawn (b) | | Available |
Xcel Energy Inc. | Xcel Energy Inc. | | $ | 1,250 | | | $ | 529 | | | $ | 721 | | Xcel Energy Inc. | | $ | 1,500 | | | $ | 158 | | | $ | 1,342 | |
PSCo | PSCo | | 700 | | | 8 | | | 692 | | PSCo | | 700 | | | 26 | | | 674 | |
NSP-Minnesota | NSP-Minnesota | | 500 | | | 9 | | | 491 | | NSP-Minnesota | | 700 | | | 11 | | | 689 | |
SPS | SPS | | 500 | | | 20 | | | 480 | | SPS | | 500 | | | 2 | | | 498 | |
NSP-Wisconsin | NSP-Wisconsin | | 150 | | | — | | | 150 | | NSP-Wisconsin | | 150 | | | — | | | 150 | |
Total | Total | | $ | 3,100 | | | $ | 566 | | | $ | 2,534 | | Total | | $ | 3,550 | | | $ | 197 | | | $ | 3,353 | |
(a)Expires in June 2024.September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facilities capacity.facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of Sept. 30, 20212022 and Dec. 31, 2020.
Term Loan Agreements — In February 2021, Xcel Energy Inc. entered into a $1.2 billion 364-Day Term Loan Agreement that matures Feb. 17, 2022. Xcel Energy has an option to extend through Feb. 16, 2023. The term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65%.
As of Sept. 30, 2021, Xcel Energy Inc.’s term loan borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | Limit | | Amount Used | | Available |
Xcel Energy Inc. | | $ | 1,200 | | | $ | 1,200 | | | $ | — | |
2021.Bilateral Credit Agreement
In April 2021,2022, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Sept. 30, 2021, NSP-Minnesota’s2022, NSP-Minnesota had $50 million of outstanding letters of credit under the $75 million bilateral credit agreement were as follows:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
NSP-Minnesota | | $ | 75 | | | $ | 41 | | | $ | 34 | |
agreement.Long-Term Borrowings and Other Financing Instruments
During the nine months ended Sept.September 30, 2021,2022, Xcel Energy Inc. and its utility subsidiaries issued the following:
•PSCoXcel Energy issued $750$700 million of 1.875%4.60% unsecured senior notes due June 1, 2032.
•NSP-Minnesota issued $500 million of 4.50% first mortgage bonds due June 15, 2031.1, 2052.
•PSCo issued $300 million of 4.10% first mortgage bonds due June 1, 2032 and $400 million of 4.50% first mortgage bonds due June 1, 2052.
•SPS issued $250$200 million of 3.15%5.15% first mortgage bonds due May 1, 2050.
•NSP-Minnesota issued $425 million of 2.25% first mortgage bonds due April 1, 2031 and $425 million of 3.20% first mortgage bonds due AprilJune 1, 2052.
•NSP-Wisconsin issued $100 million of 2.82%4.86% first mortgage bonds dudue September 15, 2052.
ATM Equity Offering — e May 1, 2051.In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares were issued (approximately $350 million). In the second quarter of 2022, 2.13 million shares of common stock were issued (approximately $150 million). As of Sept. 30, 2022, approximately $300 million remained available for sale under the ATM program.
Other Equity — Xcel Energy Inc. issued $38$34 million and $30$38 million of equity through the DRIP during the nine months ended Sept. 30, 20212022 and 2020,2021, respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30, 2022 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 1,109 | | | $ | 181 | | | $ | 15 | | | $ | 1,305 | |
C&I | | 1,734 | | | 116 | | | 6 | | | 1,856 | |
Other | | 42 | | | — | | | 2 | | | 44 | |
Total retail | | 2,885 | | | 297 | | | 23 | | | 3,205 | |
Wholesale | | 450 | | | — | | | — | | | 450 | |
Transmission | | 210 | | | — | | | — | | | 210 | |
Other | | 20 | | | 43 | | | — | | | 63 | |
Total revenue from contracts with customers | | 3,565 | | | 340 | | | 23 | | | 3,928 | |
Alternative revenue and other | | 134 | | | 17 | | | 3 | | | 154 | |
Total revenues | | $ | 3,699 | | | $ | 357 | | | $ | 26 | | | $ | 4,082 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30, 2021 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 999 | | | $ | 133 | | | $ | 12 | | | $ | 1,144 | |
C&I | | 1,515 | | | 76 | | | 7 | | | 1,598 | |
Other | | 35 | | | — | | | 1 | | | 36 | |
Total retail | | 2,549 | | | 209 | | | 20 | | | 2,778 | |
Wholesale | | 288 | | | — | | | — | | | 288 | |
Transmission | | 167 | | | — | | | — | | | 167 | |
Other | | 17 | | | 45 | | | — | | | 62 | |
Total revenue from contracts with customers | | 3,021 | | | 254 | | | 20 | | | 3,295 | |
Alternative revenue and other | | 155 | | | 14 | | | 3 | | | 172 | |
Total revenues | | $ | 3,176 | | | $ | 268 | | | $ | 23 | | | $ | 3,467 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30, 2020 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 962 | | | $ | 124 | | | $ | 11 | | | $ | 1,097 | |
C&I | | 1,340 | | | 56 | | | 5 | | | 1,401 | |
Other | | 34 | | | — | | | 2 | | | 36 | |
Total retail | | 2,336 | | | 180 | | | 18 | | | 2,534 | |
Wholesale | | 227 | | | — | | | — | | | 227 | |
Transmission | | 157 | | | — | | | — | | | 157 | |
Other | | 17 | | | 28 | | | — | | | 45 | |
Total revenue from contracts with customers | | 2,737 | | | 208 | | | 18 | | | 2,963 | |
Alternative revenue and other | | 204 | | | 11 | | | 4 | | | 219 | |
Total revenues | | $ | 2,941 | | | $ | 219 | | | $ | 22 | | | $ | 3,182 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30, 2022 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 2,723 | | | $ | 1,100 | | | $ | 30 | | | $ | 3,853 | |
C&I | | 4,385 | | | 636 | | | 15 | | | 5,036 | |
Other | | 111 | | | — | | | 25 | | | 136 | |
Total retail | | 7,219 | | | 1,736 | | | 70 | | | 9,025 | |
Wholesale | | 1,027 | | | — | | | — | | | 1,027 | |
Transmission | | 518 | | | — | | | — | | | 518 | |
Other | | 55 | | | 125 | | | — | | | 180 | |
Total revenue from contracts with customers | | 8,819 | | | 1,861 | | | 70 | | | 10,750 | |
Alternative revenue and other | | 436 | | | 62 | | | 9 | | | 507 | |
Total revenues | | $ | 9,255 | | | $ | 1,923 | | | $ | 79 | | | $ | 11,257 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30, 2021 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 2,488 | | | $ | 774 | | | $ | 33 | | | $ | 3,295 | |
C&I | | 3,830 | | | 389 | | | 22 | | | 4,241 | |
Other | | 96 | | | — | | | 5 | | | 101 | |
Total retail | | 6,414 | | | 1,163 | | | 60 | | | 7,637 | |
Wholesale | | 1,265 | | | — | | | — | | | 1,265 | |
Transmission | | 461 | | | — | | | — | | | 461 | |
Other | | 51 | | | 106 | | | — | | | 157 | |
Total revenue from contracts with customers | | 8,191 | | | 1,269 | | | 60 | | | 9,520 | |
Alternative revenue and other | | 452 | | | 95 | | | 9 | | | 556 | |
Total revenues | | $ | 8,643 | | | $ | 1,364 | | | $ | 69 | | | $ | 10,076 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30, 2020 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 2,356 | | | $ | 647 | | | $ | 32 | | | $ | 3,035 | |
C&I | | 3,481 | | | 308 | | | 20 | | | 3,809 | |
Other | | 94 | | | — | | | 4 | | | 98 | |
Total retail | | 5,931 | | | 955 | | | 56 | | | 6,942 | |
Wholesale | | 553 | | | — | | | — | | | 553 | |
Transmission | | 442 | | | — | | | — | | | 442 | |
Other | | 55 | | | 86 | | | — | | | 141 | |
Total revenue from contracts with customers | | 6,981 | | | 1,041 | | | 56 | | | 8,078 | |
Alternative revenue and other | | 449 | | | 41 | | | 11 | | | 501 | |
Total revenues | | $ | 7,430 | | | $ | 1,082 | | | $ | 67 | | | $ | 8,579 | |
Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020 represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated by reference.DifferenceReconciliation between the statutory rate and ETR:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Federal statutory rate | Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
State tax (net of federal tax effect) | State tax (net of federal tax effect) | | 5.0 | | | 5.0 | | | 5.0 | | | 5.1 | | State tax (net of federal tax effect) | | 4.9 | | | 5.0 | | | 4.9 | | | 5.0 | |
Decreases: | Decreases: | | Decreases: | |
Wind PTCs(a) | Wind PTCs(a) | | (12.1) | | | (8.0) | | | (20.0) | | | (13.2) | | Wind PTCs(a) | | (12.3) | | | (12.1) | | | (25.2) | | | (20.0) | |
Plant regulatory differences (a)(b) | Plant regulatory differences (a)(b) | | (5.8) | | | (7.2) | | | (6.0) | | | (7.4) | | Plant regulatory differences (a)(b) | | (5.8) | | | (5.8) | | | (5.5) | | | (6.0) | |
NOL carryback | | — | | | (1.9) | | | — | | | (1.0) | | |
Other tax credits, net operating loss & tax credits allowances | | Other tax credits, net operating loss & tax credits allowances | | (1.2) | | | (1.2) | | | (1.4) | | | (1.1) | |
Other (net) | Other (net) | | (1.5) | | | (2.2) | | | (1.3) | | | (2.5) | | Other (net) | | (0.3) | | | (0.3) | | | (0.1) | | | (0.2) | |
Effective income tax rate | Effective income tax rate | | 6.6 | % | | 6.7 | % | | (1.3) | % | | 2.0 | % | Effective income tax rate | | 6.3 | % | | 6.6 | % | | (6.3) | % | | (1.3) | % |
(a)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(b)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred creditstaxes are offset by corresponding revenue reductions.
Federal Audits—Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
| | | | | | | | |
Tax Years | | Expiration |
2014 — 2016
| | December 2022 |
2018 | | September 2022 |
Additionally, the statute of limitations related to certain federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to a federal tax loss carryback claim filed in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
State Audits —Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.
As of Sept. 30, 2021, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
| | | | | | | | |
State | | Year |
Colorado | | 2014 |
Minnesota | | 2013 |
Texas | | 2012 |
Wisconsin | | 2016 |
•In February 2021, Minnesota concluded its review and commenced an audit of tax years 2015 - 2018. No material adjustments have been proposed.
•In March 2021, Wisconsin began an audit of tax years 2016 - 2019. NaN material adjustments have been proposed.
•In April 2021, Texas began an audit of tax years 2016 - 2019. No material adjustments have been proposed.
•NaN other state income tax audits were in progress as of Sept. 30, 2021.
Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.
Unrecognized tax benefits — permanent vs. temporary:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Sept. 30, 2021 | | Dec. 31, 2020 |
Unrecognized tax benefit — Permanent tax positions | | $ | 46 | | | $ | 41 | |
Unrecognized tax benefit — Temporary tax positions | | 11 | | | 11 | |
Total unrecognized tax benefit | | $ | 57 | | | $ | 52 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Sept. 30, 2021 | | Dec. 31, 2020 |
NOL and tax credit carryforwards | | $ | (35) | | | $ | (31) | |
As Internal Revenue Service audits resume and the state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $27 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Sept. 30, 2021 | | Dec. 31, 2020 |
Payable for interest related to unrecognized tax benefits at beginning of period | | $ | (3) | | | $ | — | |
Interest expense related to unrecognized tax benefits | | — | | | (3) | |
Payable for interest related to unrecognized tax benefits at end of period | | $ | (3) | | | $ | (3) | |
NaN penalties were accrued related to unrecognized tax benefits as of Sept. 30, 2021 or Dec. 31, 2020.
Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock issued to employees is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions have been satisfied by the end of the reporting period.
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Common shares outstanding used in the basic and diluted EPS computation:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Shares in Millions) | (Shares in Millions) | | 2021 | | 2020 | | 2021 | | 2020 | (Shares in Millions) | | 2022 | | 2021 | | 2022 | | 2021 |
Basic | Basic | | 539 | | | 526 | | 539 | | 526 | Basic | | 548 | | | 539 | | 546 | | 539 |
Diluted (a) | Diluted (a) | | 539 | | 528 | | | 539 | | | 527 | | Diluted (a) | | 548 | | 539 | | | 546 | | | 539 | |
(a)Diluted common shares outstanding included common stock equivalents of 0.3 million and 1.6 million for the three months ended Sept.September 30, 20212022 and 2020,2021, respectively. Diluted common shares outstanding included common stock equivalents of 0.3 million and 1.0 million for the nine months ended Sept.September 30, 20212022 and 2020,2021, respectively.
| | |
8. Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
•Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds’fund investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from aan RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The valuevalues of an FTR isthese instruments are derived from, and designed to offset, the costcosts of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.these instruments. FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. GivenNet congestion costs, including the limited observabilityimpact of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.
Non-trading monthly FTR settlements, are expected to be recoveredshared through fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction and therefore changes inmechanisms. As such, the fair value of the yet to be settled portions of most FTRs are unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements.
Non-Derivative Fair Value Measurements
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approvedMPUC-approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $1.2$900 million and $1.3 billion as of Sept. 30, 2022 and $981Dec. 31, 2021, respectively, and unrealized losses were $133 million and $7 million as of Sept. 30, 20212022 and Dec. 31, 2020, respectively, and unrealized losses were $5 million as of Sept. 30, 2021, and Dec. 31, 2020.respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
| | | Sept. 30, 2021 | | Sept. 30, 2022 |
| | | Fair Value | | | Fair Value |
(Millions of Dollars) | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | Nuclear decommissioning fund (a) | | | | | | | | | | | | | Nuclear decommissioning fund (a) |
Cash equivalents | Cash equivalents | | $ | 38 | | | $ | 38 | | | $ | — | | | $ | — | | | $ | — | | | $ | 38 | | Cash equivalents | | $ | 37 | | | $ | 37 | | | $ | — | | | $ | — | | | $ | — | | | $ | 37 | |
Commingled funds | Commingled funds | | 821 | | | — | | | — | | | — | | | 1,208 | | | 1,208 | | Commingled funds | | 832 | | | — | | | — | | | — | | | 1,167 | | | 1,167 | |
Debt securities | Debt securities | | 620 | | | — | | | 643 | | | 15 | | | — | | | 658 | | Debt securities | | 696 | | | — | | | 611 | | | 9 | | | — | | | 620 | |
Equity securities | Equity securities | | 407 | | | 1,178 | | | 2 | | | — | | | — | | | 1,180 | | Equity securities | | 409 | | | 918 | | | 1 | | | — | | | — | | | 919 | |
Total | Total | | $ | 1,886 | | | $ | 1,216 | | | $ | 645 | | | $ | 15 | | | $ | 1,208 | | | $ | 3,084 | | Total | | $ | 1,974 | | | $ | 955 | | | $ | 612 | | | $ | 9 | | | $ | 1,167 | | | $ | 2,743 | |
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $204$214 million of equity method investments and $158$126 million of rabbi trust assets and miscellaneous investments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2020 |
| | | | Fair Value |
(Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | | | | | | | | | | | | |
Cash equivalents | | $ | 40 | | | $ | 40 | | | $ | — | | | $ | — | | | $ | — | | | $ | 40 | |
Commingled funds | | 787 | | | — | | | — | | | — | | | 1,041 | | | 1,041 | |
Debt securities | | 528 | | | — | | | 572 | | | 13 | | | — | | | 585 | |
Equity securities | | 446 | | | 1,109 | | | 2 | | | — | | | — | | | 1,111 | |
Total | | $ | 1,801 | | | $ | 1,149 | | | $ | 574 | | | $ | 13 | | | $ | 1,041 | | | $ | 2,777 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2021 |
| | | | Fair Value |
(Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) |
Cash equivalents | | $ | 64 | | | $ | 64 | | | $ | — | | | $ | — | | | $ | — | | | $ | 64 | |
Commingled funds | | 856 | | | — | | | — | | | — | | | 1,294 | | | 1,294 | |
Debt securities | | 631 | | | — | | | 666 | | | 9 | | | — | | | 675 | |
Equity securities | | 411 | | | 1,222 | | | 1 | | | — | | | — | | | 1,223 | |
Total | | $ | 1,962 | | | $ | 1,286 | | | $ | 667 | | | $ | 9 | | | $ | 1,294 | | | $ | 3,256 | |
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $165$208 million of equity method investments and $154$164 million of rabbi trust assets and other miscellaneous investments.
For the three and nine months ended Sept. 30, 20212022 and 2020,2021, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Sept. 30, 2021:2022:
| | | Final Contractual Maturity | | Final Contractual Maturity |
(Millions of Dollars) | (Millions of Dollars) | | Due in 1 year or Less | | Due in 1 to 5 Years | | Due in 5 to 10 Years | | Due after 10 years | | Total | (Millions of Dollars) | | Due in 1 year or Less | | Due in 1 to 5 Years | | Due in 5 to 10 Years | | Due after 10 years | | Total |
Debt securities | Debt securities | | $ | 2 | | | $ | 153 | | | $ | 204 | | | $ | 299 | | | $ | 658 | | Debt securities | | $ | 5 | | | $ | 190 | | | $ | 227 | | | $ | 198 | | | $ | 620 | |
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan.
Cost and fair value of assets held in rabbi trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Sept. 30, 2021 |
| | | | Fair Value |
(Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | |
Cash equivalents | | $ | 17 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 17 | |
Mutual funds | | 71 | | | 84 | | | — | | | — | | | 84 | |
Total | | $ | 88 | | | $ | 101 | | | $ | — | | | $ | — | | | $ | 101 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Sept. 30, 2022 |
| | | | Fair Value |
(Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | |
Cash equivalents | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | |
Mutual funds | | 75 | | | 73 | | | — | | | — | | | 73 | |
Total | | $ | 76 | | | $ | 74 | | | $ | — | | | $ | — | | | $ | 74 | |
| | | Dec. 31, 2020 | | Dec. 31, 2021 |
| | | Fair Value | | | Fair Value |
(Millions of Dollars) | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | Rabbi Trusts (a) | | | | | | | | | | | Rabbi Trusts (a) | | | | | | | | | | |
Cash equivalents | Cash equivalents | | $ | 32 | | | $ | 32 | | | $ | — | | | $ | — | | | $ | 32 | | Cash equivalents | | $ | 20 | | | $ | 20 | | | $ | — | | | $ | — | | | $ | 20 | |
Mutual funds | Mutual funds | | 60 | | | 70 | | | — | | | — | | | 70 | | Mutual funds | | 75 | | | 89 | | | — | | | — | | | 89 | |
Total | Total | | $ | 92 | | | $ | 102 | | | $ | — | | | $ | — | | | $ | 102 | | Total | | $ | 95 | | | $ | 109 | | | $ | — | | | $ | — | | | $ | 109 | |
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets.
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
As of Sept. 30, 2021,2022, accumulated other comprehensive loss related to interest rate derivatives included $6$2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Sept. 30, 2022, Xcel Energy had no unsettled interest rate derivatives.
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives.
Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. The classification of gains or losses for these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms. As of Sept. 30, 2021,2022, Xcel Energy had no commodity contracts designated as cash flow hedges.
Xcel Energy also enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards, options and FTRs:
| (Amounts in Millions) (a)(b) | (Amounts in Millions) (a)(b) | | Sept. 30, 2021 | | Dec. 31, 2020 | (Amounts in Millions) (a)(b) | | Sept. 30, 2022 | | Dec. 31, 2021 |
Megawatt hours of electricity | Megawatt hours of electricity | | 101 | | | 87 | | Megawatt hours of electricity | | 82 | | | 80 | |
Million British thermal units of natural gas | Million British thermal units of natural gas | | 184 | | | 175 | | Million British thermal units of natural gas | | 151 | | | 156 | |
|
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts, prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
As of Sept. 30, 2021, 62022, five of Xcel Energy’s 10ten most significant counterparties for these activities, comprising $121$86 million, or 40%30%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. NaNThree of the 10ten most significant counterparties, comprising $29$61 million, or 10%22%, of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. NaNTwo of these significant counterparties, comprising $44$68 million, or 14%24%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaNSix of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Impact of Derivative Activity —
| | | | | | | | | | | | | | |
| | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities |
Three Months Ended Sept. 30, 2022 | | | | |
| | |
| | | | |
| | | | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | 6 | |
Natural gas commodity | | — | | | (6) | |
Total | | $ | — | | | $ | — | |
| | | | |
Nine Months Ended Sept. 30, 2022 | | | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | 21 | | | $ | — | |
Total | | $ | 21 | | | $ | — | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | 106 | |
Natural gas commodity | | — | | | (3) | |
Total | | $ | — | | | $ | 103 | |
| | | | |
| | | | |
Three Months Ended Sept. 30, 2021 | | | | |
Derivatives designated as cash flow hedges: | | | | |
Interest rate | | $ | 4 | | | $ | — | |
Total | | $ | 4 | | | $ | — | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | 5 | |
Natural gas commodity | | — | | | 57 | |
Total | | $ | — | | | $ | 62 | |
| | | | |
Nine Months Ended Sept. 30, 2021 | | | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | 5 | | | $ | — | |
Total | | $ | 5 | | | $ | — | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | 18 | |
Natural gas commodity | | — | | | 57 | |
Total | | $ | — | | | $ | 75 | |
| | | | |
| | | | |
Three Months Ended Sept. 30, 2020 | | | | |
| | | | |
| | | | |
| | | | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | (3) | |
Natural gas commodity | | — | | | 2 | |
Total | | $ | — | | | $ | (1) | |
| | | | |
Nine Months Ended Sept. 30, 2020 | | | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | (13) | | | $ | — | |
Total | | $ | (13) | | | $ | — | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | (3) | |
Natural gas commodity | | — | | | (1) | |
Total | | $ | — | | | $ | (4) | |
| | | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | Pre-Tax Gains (Losses) Recognized During the Period in Income | | | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | Pre-Tax Gains (Losses) Recognized During the Period in Income | |
(Millions of Dollars) | (Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | | (Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory Assets and (Liabilities) | |
Three Months Ended Sept. 30, 2022 | | Three Months Ended Sept. 30, 2022 | | | | | |
Derivatives designated as cash flow hedges: | | Derivatives designated as cash flow hedges: | |
Interest rate | | Interest rate | | $ | 1 | | (a) | $ | — | | | $ | — | | |
Total | | Total | | $ | 1 | | | $ | — | | | $ | — | | |
Other derivative instruments: | | Other derivative instruments: | | | | | |
Commodity trading | | Commodity trading | | $ | — | | | $ | — | | | $ | 13 | | (b) |
Electric commodity | | Electric commodity | | — | | | 6 | | (c) | — | | |
| Total | | Total | | $ | — | | | $ | 6 | | | $ | 13 | | |
| Nine Months Ended Sept. 30, 2022 | | Nine Months Ended Sept. 30, 2022 | |
Derivatives designated as cash flow hedges: | | Derivatives designated as cash flow hedges: | |
Interest rate | | Interest rate | | $ | 5 | | (a) | $ | — | | | $ | — | | |
Total | | Total | | $ | 5 | | | $ | — | | | $ | — | | |
Other derivative instruments: | | Other derivative instruments: | | | | | |
Commodity trading | | Commodity trading | | $ | — | | | $ | — | | | $ | 21 | | (b) |
Electric commodity | | Electric commodity | | — | | | (31) | | (c) | — | | |
Natural gas commodity | | Natural gas commodity | | — | | | 4 | | (d) | (17) | | (d)(e) |
Total | | Total | | $ | — | | | $ | (27) | | | $ | 4 | | |
| Three Months Ended Sept. 30, 2021 | Three Months Ended Sept. 30, 2021 | | | | | | Three Months Ended Sept. 30, 2021 | |
Derivatives designated as cash flow hedges: | Derivatives designated as cash flow hedges: | | Derivatives designated as cash flow hedges: | |
Interest rate | Interest rate | | $ | 2 | | (a) | $ | — | | | $ | — | | | Interest rate | | $ | 2 | | (a) | $ | — | | | $ | — | | |
Total | Total | | $ | 2 | | | $ | — | | | $ | — | | | Total | | $ | 2 | | | $ | — | | | $ | — | | |
Other derivative instruments: | Other derivative instruments: | | | | | | | | Other derivative instruments: | | | | | |
Commodity trading | Commodity trading | | $ | — | | | $ | — | | | $ | 1 | | (b) | Commodity trading | | $ | — | | | $ | — | | | $ | 1 | | (b) |
Electric commodity | Electric commodity | | — | | | 3 | | (c) | — | | | Electric commodity | | — | | | 3 | | (c) | — | | |
| Total | Total | | $ | — | | | $ | 3 | | | $ | 1 | | | Total | | $ | — | | | $ | 3 | | | $ | 1 | | |
| Nine Months Ended Sept. 30, 2021 | Nine Months Ended Sept. 30, 2021 | | Nine Months Ended Sept. 30, 2021 | |
Derivatives designated as cash flow hedges: | Derivatives designated as cash flow hedges: | | Derivatives designated as cash flow hedges: | |
Interest rate | Interest rate | | $ | 7 | | (a) | $ | — | | | $ | — | | | Interest rate | | $ | 7 | | (a) | $ | — | | | $ | — | | |
Total | Total | | $ | 7 | | | $ | — | | | $ | — | | | Total | | $ | 7 | | | $ | — | | | $ | — | | |
Other derivative instruments: | Other derivative instruments: | | | | | | | | Other derivative instruments: | | | | | | | |
Commodity trading | Commodity trading | | $ | — | | | $ | — | | | $ | 49 | | (b) | Commodity trading | | $ | — | | | $ | — | | | $ | 49 | | (b) |
Electric commodity | Electric commodity | | — | | | (26) | | (c) | — | | | Electric commodity | | — | | | (26) | | (c) | — | | |
Natural gas commodity | Natural gas commodity | | — | | | 8 | | (d) | (10) | | (d) | Natural gas commodity | | — | | | 8 | | (d) | (10) | | (d)(e) |
Total | Total | | $ | — | | | $ | (18) | | | $ | 39 | | | Total | | $ | — | | | $ | (18) | | | $ | 39 | | |
| Three Months Ended Sept. 30, 2020 | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | 1 | | (a) | $ | — | | | $ | — | | | |
Total | | $ | 1 | | | $ | — | | | $ | — | | | |
Other derivative instruments: | | | | | | | | |
Commodity trading | | $ | — | | | $ | — | | | $ | 2 | | (b) | |
Electric commodity | | — | | | (3) | | (c) | — | | | |
Total | | $ | — | | | $ | (3) | | | $ | 2 | | | |
| Nine Months Ended Sept. 30, 2020 | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | 5 | | (a) | $ | — | | | $ | — | | | |
Total | | $ | 5 | | | $ | — | | | $ | — | | | |
Other derivative instruments: | | | | | | | | |
Commodity trading | | $ | — | | | $ | — | | | $ | (1) | | (b) | |
Electric commodity | | — | | | (6) | | (c) | — | | | |
Natural gas commodity | | — | | | 5 | | (d) | (6) | | (d) | |
Total | | $ | — | | | $ | (1) | | | $ | (7) | | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. All FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.
(d)Amounts for both the three and nine months ended Sept. 30, 2021 and 2020 included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Remaining settlement losses for both the three and nine months ended Sept. 30, 2021 and 2020 relate to natural gas operations and were recordedRecorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, or liability, as appropriate.
(e)Relates primarily to option premium amortization.
Xcel Energy had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 20212022 and 2020.2021.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. At Sept. 30, 20212022 and Dec. 31, 2020,2021, there were $2$5 million and $4$3 million, respectively, of derivative liabilities with such underlying contract provisions. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of Sept. 30, 20212022 and Dec. 31, 2020,2021, there were approximately $62$90 million and $60$64 million, respectively, of derivative liabilities with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 20212022 and Dec. 31, 20202021.
Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis:basis were as follows:
| | | Sept. 30, 2021 | | Dec. 31, 2020 | | Sept. 30, 2022 | | Dec. 31, 2021 |
| | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total |
(Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | |
Current derivative assets | Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | — | | | $ | 4 | | | $ | — | | | $ | 4 | | | $ | — | | | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | |
| Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 50 | | | $ | 240 | | | $ | 23 | | | $ | 313 | | | $ | (253) | | | $ | 60 | | | $ | 2 | | | $ | 67 | | | $ | 1 | | | $ | 70 | | | $ | (52) | | | $ | 18 | | Commodity trading | | $ | 53 | | | $ | 184 | | | $ | 47 | | | $ | 284 | | | $ | (211) | | | $ | 73 | | | $ | 22 | | | $ | 137 | | | $ | 21 | | | $ | 180 | | | $ | (134) | | | $ | 46 | |
Electric commodity(b) | Electric commodity(b) | | — | | | — | | | 83 | | | 83 | | | (1) | | | 82 | | | — | | | — | | | 20 | | | 20 | | | (1) | | | 19 | | Electric commodity(b) | | — | | | — | | | 358 | | | 358 | | | (4) | | | 354 | | | — | | | — | | | 57 | | | 57 | | | (1) | | | 56 | |
Natural gas commodity | Natural gas commodity | | — | | | 79 | | | — | | | 79 | | | — | | | 79 | | | — | | | 9 | | | — | | | 9 | | | — | | | 9 | | Natural gas commodity | | — | | | 26 | | | — | | | 26 | | | — | | | 26 | | | — | | | 18 | | | — | | | 18 | | | — | | | 18 | |
Total current derivative assets | Total current derivative assets | | $ | 50 | | | $ | 323 | | | $ | 106 | | | $ | 479 | | | $ | (254) | | | 225 | | | $ | 2 | | | $ | 76 | | | $ | 21 | | | $ | 99 | | | $ | (53) | | | 46 | | Total current derivative assets | | $ | 53 | | | $ | 210 | | | $ | 405 | | | $ | 668 | | | $ | (215) | | | 453 | | | $ | 22 | | | $ | 155 | | | $ | 78 | | | $ | 255 | | | $ | (135) | | | 120 | |
PPAs (b) | | | | | | | | | | | | 3 | | | | | | | | | | | | | 3 | | |
PPAs (c) | | PPAs (c) | | | | | | | | | | | | 3 | | | | | | | | | | | | | 3 | |
Current derivative instruments | Current derivative instruments | | $ | 228 | | | $ | 49 | | Current derivative instruments | | $ | 456 | | | $ | 123 | |
Noncurrent derivative assets | Noncurrent derivative assets | | | | | Noncurrent derivative assets | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 23 | | | $ | 72 | | | $ | 99 | | | $ | 194 | | | $ | (129) | | | $ | 65 | | | $ | 8 | | | $ | 66 | | | $ | 8 | | | $ | 82 | | | $ | (62) | | | $ | 20 | | Commodity trading | | $ | 50 | | | $ | 64 | | | $ | 92 | | | $ | 206 | | | $ | (120) | | | $ | 86 | | | $ | 16 | | | $ | 63 | | | $ | 89 | | | $ | 168 | | | $ | (107) | | | $ | 61 | |
| Total noncurrent derivative assets | Total noncurrent derivative assets | | $ | 23 | | | $ | 72 | | | $ | 99 | | | $ | 194 | | | $ | (129) | | | 65 | | | $ | 8 | | | $ | 66 | | | $ | 8 | | | $ | 82 | | | $ | (62) | | | 20 | | Total noncurrent derivative assets | | $ | 50 | | | $ | 64 | | | $ | 92 | | | $ | 206 | | | $ | (120) | | | 86 | | | $ | 16 | | | $ | 63 | | | $ | 89 | | | $ | 168 | | | $ | (107) | | | 61 | |
PPAs (b) | | | | | | | | | | | | 7 | | | | | | | | | | | | | 10 | | |
PPAs (c) | | PPAs (c) | | | | | | | | | | | | 4 | | | | | | | | | | | | | 6 | |
Noncurrent derivative instruments | Noncurrent derivative instruments | | $ | 72 | | | $ | 30 | | Noncurrent derivative instruments | | $ | 90 | | | $ | 67 | |
| | | Sept. 30, 2021 | | Dec. 31, 2020 | | Sept. 30, 2022 | | Dec. 31, 2021 |
| | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total |
(Millions of Dollars) | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | |
Current derivative liabilities | Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 48 | | | $ | 239 | | | $ | 25 | | | $ | 312 | | | $ | (253) | | | $ | 59 | | | $ | 4 | | | $ | 64 | | | $ | 17 | | | $ | 85 | | | $ | (58) | | | $ | 27 | | Commodity trading | | $ | 44 | | | $ | 223 | | | $ | 23 | | | $ | 290 | | | $ | (219) | | | $ | 71 | | | $ | 19 | | | $ | 148 | | | $ | 20 | | | $ | 187 | | | $ | (143) | | | $ | 44 | |
Electric commodity(b) | Electric commodity(b) | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | | Electric commodity(b) | | — | | | — | | | 4 | | | 4 | | | (4) | | | — | | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | |
Natural gas commodity | Natural gas commodity | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | — | | | 9 | | | — | | | 9 | | Natural gas commodity | | — | | | 12 | | | — | | | 12 | | | — | | | 12 | | | — | | | 8 | | | — | | | 8 | | | — | | | 8 | |
Total current derivative liabilities | Total current derivative liabilities | | $ | 48 | | | $ | 239 | | | $ | 26 | | | $ | 313 | | | $ | (254) | | | 59 | | | $ | 4 | | | $ | 73 | | | $ | 18 | | | $ | 95 | | | $ | (59) | | | 36 | | Total current derivative liabilities | | $ | 44 | | | $ | 235 | | | $ | 27 | | | $ | 306 | | | $ | (223) | | | 83 | | | $ | 19 | | | $ | 156 | | | $ | 21 | | | $ | 196 | | | $ | (144) | | | 52 | |
PPAs (b) | | | | | | | | | | | | 17 | | | | | | | | | | | | | 17 | | |
PPAs (c) | | PPAs (c) | | | | | | | | | | | | 17 | | | | | | | | | | | | | 17 | |
Current derivative instruments | Current derivative instruments | | $ | 76 | | | $ | 53 | | Current derivative instruments | | $ | 100 | | | $ | 69 | |
Noncurrent derivative liabilities | Noncurrent derivative liabilities | | | | | Noncurrent derivative liabilities | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 22 | | | $ | 69 | | | $ | 120 | | | $ | 211 | | | $ | (156) | | | $ | 55 | | | $ | 3 | | | $ | 58 | | | $ | 60 | | | $ | 121 | | | $ | (47) | | | $ | 74 | | Commodity trading | | $ | 59 | | | $ | 86 | | | $ | 68 | | | $ | 213 | | | $ | (132) | | | $ | 81 | | | $ | 18 | | | $ | 48 | | | $ | 127 | | | $ | 193 | | | $ | (128) | | | $ | 65 | |
Total noncurrent derivative liabilities | Total noncurrent derivative liabilities | | $ | 22 | | | $ | 69 | | | $ | 120 | | | $ | 211 | | | $ | (156) | | | 55 | | | $ | 3 | | | $ | 58 | | | $ | 60 | | | $ | 121 | | | $ | (47) | | | 74 | | Total noncurrent derivative liabilities | | $ | 59 | | | $ | 86 | | | $ | 68 | | | $ | 213 | | | $ | (132) | | | 81 | | | $ | 18 | | | $ | 48 | | | $ | 127 | | | $ | 193 | | | $ | (128) | | | 65 | |
PPAs (b) | | | | | | | | | | | | 44 | | | | | | | | | | | | | 57 | | |
PPAs (c) | | PPAs (c) | | | | | | | | | | | | 33 | | | | | | | | | | | | | 40 | |
Noncurrent derivative instruments | Noncurrent derivative instruments | | $ | 99 | | | $ | 131 | | Noncurrent derivative instruments | | $ | 114 | | | $ | 105 | |
(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements atagreement. At Sept. 30, 20212022 and Dec. 31, 2020. At both Sept. 30, 2021, derivatives include $2 million and Dec. 31, 2020, derivative assets and liabilities include $15 million ofno obligations to return cash collateral.collateral, respectively. At Sept. 30, 20212022 and Dec. 31, 2020,2021, derivative assets and liabilities include rights to reclaim cash collateral of $42$22 million and $6$30 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Amounts relate to FTR instruments administered by MISO and SPP (annual auctions occurring in the second quarter). These instruments are utilized/intended to offset the impacts of transmission system congestion. Higher congestion costs have led to an increase in the fair value of FTRs. Due to regulatory recovery, fair values for FTRs are offset/deferred as a regulatory asset or liability and do not have a material impact on net income.
(c)During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 commodity derivatives:
| | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
(Millions of Dollars) | (Millions of Dollars) | | 2021 | | 2020 | (Millions of Dollars) | | 2022 | | 2021 |
Balance at July 1 | Balance at July 1 | | $ | 71 | | | $ | 34 | | Balance at July 1 | | $ | 485 | | | $ | 71 | |
Purchases | | 2 | | | — | | |
Settlements | | (53) | | | (17) | | |
Purchases / Issuances (a) | | Purchases / Issuances (a) | | 4 | | | 2 | |
Settlements (a) | | Settlements (a) | | (106) | | | (53) | |
Net transactions recorded during the period: | Net transactions recorded during the period: | | Net transactions recorded during the period: | |
Gains (losses) recognized in earnings (a) | | 12 | | | (25) | | |
Net gains recognized as regulatory assets and liabilities | | 27 | | | 2 | | |
Gains recognized in earnings (b) | | Gains recognized in earnings (b) | | 16 | | | 12 | |
Net gains recognized as regulatory assets and liabilities (a) | | Net gains recognized as regulatory assets and liabilities (a) | | 3 | | | 27 | |
Balance at Sept. 30 | Balance at Sept. 30 | | $ | 59 | | | $ | (6) | | Balance at Sept. 30 | | $ | 402 | | | $ | 59 | |
| | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | (Millions of Dollars) | | 2021 | | 2020 | (Millions of Dollars) | | 2022 | | 2021 |
Balance at Jan. 1 | Balance at Jan. 1 | | $ | (49) | | | $ | 4 | | Balance at Jan. 1 | | $ | 19 | | | $ | (49) | |
Purchases | | 65 | | | 49 | | |
Settlements | | (101) | | | (59) | | |
Purchases / Issuances (a) | | Purchases / Issuances (a) | | 398 | | | 65 | |
Settlements (a) | | Settlements (a) | | (286) | | | (101) | |
Net transactions recorded during the period: | Net transactions recorded during the period: | | Net transactions recorded during the period: | |
Gains (losses) recognized in earnings (a) | | 59 | | | (11) | | |
Net gains recognized as regulatory assets and liabilities | | 85 | | | 11 | | |
Gains recognized in earnings (b) | | Gains recognized in earnings (b) | | 136 | | | 59 | |
Net gains recognized as regulatory assets and liabilities (a) | | Net gains recognized as regulatory assets and liabilities (a) | | 135 | | | 85 | |
Balance at Sept. 30 | Balance at Sept. 30 | | $ | 59 | | | $ | (6) | | Balance at Sept. 30 | | $ | 402 | | | $ | 59 | |
(a)Presented amounts relateRelates primarily to FTR instruments held atadministered by MISO and SPP (annual auctions occurring in the endsecond quarter). These instruments are utilized/intended to offset the impacts of transmission system congestion. Higher congestion costs have led to an increase in the period. The consolidated income statement also includes gainsfair value of FTRs. Due to regulatory recovery, changes in fair value are deferred as a regulatory asset or liability and do not have a material impact on net income.
(b)Relates to commodity trading and is subject to offsetting losses on Levelof derivative instruments categorized as levels 1 and 2 instruments, and Level 3 instruments settled duringin the period.consolidated income statement.
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 20212022 and 2020.2021.
Fair Value of Long-Term Debt
Other financial instruments for which the carrying amount did not equal fair value:
| | | Sept. 30, 2021 | | Dec. 31, 2020 | | Sept. 30, 2022 | | Dec. 31, 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Long-term debt, including current portion | Long-term debt, including current portion | | $ | 21,600 | | | $ | 24,657 | | | $ | 20,066 | | | $ | 24,412 | | Long-term debt, including current portion | | $ | 23,960 | | | $ | 20,560 | | | $ | 22,380 | | | $ | 25,232 | |
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Sept. 30, 20212022 and Dec. 31, 20202021 and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
| | |
9. Benefit Plans and Other Postretirement Benefits |
Components of Net Periodic Benefit Cost (Credit)
| | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits | (Millions of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits |
Service cost | Service cost | | $ | 26 | | | $ | 24 | | | $ | — | | | $ | — | | Service cost | | $ | 24 | | | $ | 26 | | | $ | — | | | $ | — | |
Interest cost (a) | Interest cost (a) | | 26 | | | 31 | | | 4 | | | 5 | | Interest cost (a) | | 28 | | | 26 | | | 3 | | | 4 | |
Expected return on plan assets (a) | Expected return on plan assets (a) | | (52) | | | (52) | | | (4) | | | (5) | | Expected return on plan assets (a) | | (52) | | | (52) | | | (4) | | | (4) | |
Amortization of prior service credit (a) | Amortization of prior service credit (a) | | — | | | (1) | | | (2) | | | (2) | | Amortization of prior service credit (a) | | — | | | — | | | (2) | | | (2) | |
Amortization of net loss (a) | Amortization of net loss (a) | | 27 | | | 25 | | | 1 | | | 1 | | Amortization of net loss (a) | | 19 | | | 27 | | | 1 | | | 1 | |
Settlement charge (b) | Settlement charge (b) | | 39 | | | — | | | — | | | — | | Settlement charge (b) | | 55 | | | 39 | | | — | | | — | |
Net periodic benefit cost (credit) | Net periodic benefit cost (credit) | | 66 | | | 27 | | | (1) | | | (1) | | Net periodic benefit cost (credit) | | 74 | | | 66 | | | (2) | | | (1) | |
Effects of regulation | Effects of regulation | | (31) | | | 4 | | | 1 | | | 1 | | Effects of regulation | | (37) | | | (31) | | | 1 | | | 1 | |
Net benefit cost (credit) recognized for financial reporting | Net benefit cost (credit) recognized for financial reporting | | $ | 35 | | | $ | 31 | | | $ | — | | | $ | — | | Net benefit cost (credit) recognized for financial reporting | | $ | 37 | | | $ | 35 | | | $ | (1) | | | $ | — | |
| | | Nine Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits | (Millions of Dollars) | | Pension Benefits | | Postretirement Health Care Benefits |
Service cost | Service cost | | $ | 78 | | | $ | 72 | | | $ | 1 | | | $ | 1 | | Service cost | | $ | 73 | | | $ | 78 | | | $ | 1 | | | $ | 1 | |
Interest cost (a) | Interest cost (a) | | 78 | | | 94 | | | 11 | | | 14 | | Interest cost (a) | | 83 | | | 78 | | | 11 | | | 11 | |
Expected return on plan assets (a) | Expected return on plan assets (a) | | (155) | | | (156) | | | (13) | | | (15) | | Expected return on plan assets (a) | | (156) | | | (155) | | | (13) | | | (13) | |
Amortization of prior service credit (a) | Amortization of prior service credit (a) | | (1) | | | (3) | | | (6) | | | (6) | | Amortization of prior service credit (a) | | (1) | | | (1) | | | (5) | | | (6) | |
Amortization of net loss (a) | Amortization of net loss (a) | | 81 | | | 74 | | | 4 | | | 3 | | Amortization of net loss (a) | | 56 | | | 81 | | | 2 | | | 4 | |
Settlement charge (b) | Settlement charge (b) | | 39 | | | — | | | — | | | — | | Settlement charge (b) | | 54 | | | 39 | | | — | | | — | |
Net periodic benefit cost (credit) | Net periodic benefit cost (credit) | | 120 | | | 81 | | | (3) | | | (3) | | Net periodic benefit cost (credit) | | 109 | | | 120 | | | (4) | | | (3) | |
Effects of regulation | Effects of regulation | | (32) | | | 7 | | | 2 | | | 2 | | Effects of regulation | | (30) | | | (32) | | | 2 | | | 2 | |
Net benefit cost (credit) recognized for financial reporting | Net benefit cost (credit) recognized for financial reporting | | $ | 88 | | | $ | 88 | | | $ | (1) | | | $ | (1) | | Net benefit cost (credit) recognized for financial reporting | | $ | 79 | | | $ | 88 | | | $ | (2) | | | $ | (1) | |
|
(a)The components of net periodic cost other than the service cost component are included in the line item “Other (expense) income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
(b)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the third quarter of 2022 and 2021, as a result of lump-sum distributions during the 2022 and 2021 plan year,years, Xcel Energy recorded a total pension settlement chargecharges of $55 million and $39 million, respectively, the majority of which waswere not recognized in earnings due to the effects of regulation. A total of $7 million and $4 million of that amount wasthose amounts were recorded in other expense in the third quarter 2021.of 2022 and 2021, respectively.
In January 2021,2022, contributions of $125$50 million were made across 4four of Xcel Energy’s pension plans.plans. Xcel Energy does not expect additional pension contributions during 2021.2022.
| | |
10. Commitments and Contingencies |
The following includes commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.
Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
NaNOne case remains active which includes an MDLa multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado The Court issued a ruling on June 30, 2022 granting plaintiffs’ class certification. Defendants will work together to prepare and file a petition appealing the class — In February 2019, the MDL panel remanded Breckenridge backcertification ruling to the U.S. District Court in Colorado. Settlement of approximately $3 million was reached in February 2021. In July 2021, the settlement was approved.
Arandell Corp. — The trial has been vacated and will be rescheduled after the court rules on the pending motions for reconsideration and for class certification.Seventh Circuit. Xcel Energy has concluded that a loss is remote for the remaining lawsuit.
Comanche Unit 3 Litigation — In September 2021, CORE filed a lawsuit in Denver County District Court. CORE alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion and dismissed CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In February 2022, CORE disclosed that it is claiming in excess of $125 million in total damages.
In April 2022, CORE filed a supplement to include the January 2022 outage. It claims additional undisclosed damages arising from this event. PSCo continues to believe CORE's claims are without merit.
Rate Matters and Other
Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.fuel clause adjustment.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.
In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA.fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.
In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota. A final decision by the MPUC is pending.expected in mid-2023. A loss related to this matter is deemed remote.
Westmoreland Arbitration —In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPA and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards.
NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for Nov. 15, 2021. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined.
MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit subsequently vacated and remanded Opinion No. 551.
In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a requestsubsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the secondapplicable complaint without refunds.
In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint.
In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not changeperiods based on the ROE effective Sept. 28, 2016, and forin the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in ROE for the first complaint period, second complaint period, and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.most recent applicable opinions.
The MISO TOs and various other parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-Bthe FERC’s most recent applicable opinions at the D.C. Circuit. A hearing is expected inIn August 2022, the fourth quarter of 2021 with a decision anticipated inD.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders, and remanded the first half of 2022.
issue back to FERC NOPR on ROE Incentive Adders — In April 2021, the FERC issued a NOPR proposing to limit collection of ROE incentive adders for RTO membership to the first three years after an entity begins participation in an RTO. If adopted as a final rule, NSP-Minnesota, NSP-Wisconsin and SPS would prospectively discontinue charging their current 50 basis point ROE incentive adders. Amounts related to a discontinuance of the adder would ultimately be offset by an increase in retail rates, subject to future rate cases.further proceedings, which remain pending.
SPP OATT Upgrade Costs — Costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade under the SPP OATT. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015.
In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In August 2021, the D.C. Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates.
In October 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. In February 2022, FERC has asked that this appeal be stayed until early 2022, in order to provide FERC with time to issueissued an order onrejecting SPS’ April 2018 rehearing request. The D.C. Circuitrequest for hearing. SPS has appealed that order. That appeal may resume after that FERC order is issued.has been combined with SPS’ prior appeal.
Contract Termination — SPS and LP&L have a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the ERCOTElectric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million, (lump sum or annual installments), to the benefit of SPS’ remaining customers. LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The settlement agreement is subject to approval by the PUCT and FERC.
Comanche Unit 3 Litigation — In February 2021, Approval steps are in process, but approval timing from the joint owners of Comanche Unit 3 (CORE Electric Cooperative, formerly known as Intermountain Rural Electrical Association, and Holy Cross Electric) served PSCo with a notice of claim related to Comanche Unit 3's operation and availability.
Discussions with Holy Cross Electric are proceeding pursuant to a contractual dispute resolution process and the amount of any alleged damages depends on multiple factors andPUCT is currently unknown.
In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado state court seeking an unspecified amount of damages. CORE Electric Cooperative alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo is continuing to assess legal options in response to the Complaint including assertions of affirmative defenses.
GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The proposed rule would establish an annual forecast of GCA costs for each utility and allow each utility to recover only 90%-95% of any costs in excess of the forecasted amount. The proposed rule would allow utilities to earn an incentive equal to an undefined portion of any savings relative to forecasted costs. Comments were filed and requested that the CPUC delay the rule making process until after the 2021-2022 heating season; in part because utilities have already proceeded with purchasing gas for the upcoming heating season in accordance with prior CPUC decisions. In August 2021, the CPUC announced they would postpone a decision to a future date.uncertain.
Environmental
MGP, Landfill and Disposal Sites
Xcel Energy is investigating, remediating or performing post-closure actions at 14 MGP, landfill or other disposal sites across its service territories.territories, excluding sites that are being addressed under current coal ash regulations (see below).
Xcel Energy has recognized its best estimate of costs/liabilities from final resolution of these issues, however, the outcome and timing isare unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCRapplicable landfills and surface impoundments. Currently,impoundments as well as perform corrective actions where offsite groundwater has been impacted.
As of Sept. 30, 2022, Xcel Energy has 8had eight regulated ash units in operation.
Xcel Energy is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, increases above background concentrations were detected at 4 locations. Based on further assessments, PSCo is evaluating optionscurrently exploring an agreement with a third party that would excavate and process ash for beneficial use (at two sites) at a cost of approximately $43 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.
Investigation and feasibility studies for additional corrective action at 2 locations, 1 of which indicates potentialrelated to offsite impactsgroundwater are ongoing (at two sites). While the results are uncertain, additional costs are estimated to groundwater. The total cost is uncertain, but could be up to $35 million. PSCo is continuingAn estimated liability has been recorded for the portion of these actions that are estimable, and are expected to assessbe fully recoverable through regulatory mechanisms.
Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the financialEPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species. Estimated capital expenditures of approximately $40 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory impacts.mechanisms.
Environmental Requirements — Air
Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes sulfur dioxide emission limitations which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In August 2020,2017, the Fifth Circuit remanded the rule to the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected byreconsideration (leaving the August 2018 D.C. Circuit ruling. This final rule required Xcel Energy to expedite closure plans for 2 impoundments.
stay in effect). In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replacefuture rulemaking, the clay lined impoundment at a cost of $9 million. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.
PSCo also built an alternative collection and treatment system to remove the Comanche Station bottom ash pond from service. The total cost of the alternate treatment system is approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline, but was not able to remove the pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the EPA. PSCo will also now proceed with closure of the pond, with an estimated cost of $3 million. Closure costs for existing impoundmentsEPA may address whether further sulfur dioxide emission reductions are included in the calculation of the asset retirement obligation.necessary.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.
Components of lease expense:
| | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
(Millions of Dollars) | (Millions of Dollars) | | 2021 | | 2020 | (Millions of Dollars) | | 2022 | | 2021 |
Operating leases | Operating leases | | | | | Operating leases | | | | |
PPA capacity payments | PPA capacity payments | | $ | 56 | | | $ | 56 | | PPA capacity payments | | $ | 59 | | | $ | 56 | |
Other operating leases (a) | Other operating leases (a) | | 2 | | | 5 | | Other operating leases (a) | | 8 | | | 2 | |
Total operating lease expense (b) | Total operating lease expense (b) | | $ | 58 | | | $ | 61 | | Total operating lease expense (b) | | $ | 67 | | | $ | 58 | |
Finance leases | Finance leases | | | | | Finance leases | | | | |
Amortization of ROU assets | Amortization of ROU assets | | $ | 2 | | | $ | 2 | | Amortization of ROU assets | | $ | 1 | | | $ | 2 | |
Interest expense on lease liability | Interest expense on lease liability | | 4 | | | 4 | | Interest expense on lease liability | | 4 | | | 4 | |
Total finance lease expense | Total finance lease expense | | $ | 6 | | | $ | 6 | | Total finance lease expense | | $ | 5 | | | $ | 6 | |
(a)Includes short-term lease expense of $1 million for 2022 and $2 million for 2021 and 2020, respectively.2021.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
| | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2021 | | 2020 |
Operating leases | | | | |
PPA capacity payments | | $ | 170 | | | $ | 145 | |
Other operating leases (a) | | 19 | | 22 |
Total operating lease expense (b) | | $ | 189 | | | $ | 167 | |
Finance leases | | | | |
Amortization of ROU assets | | $ | 6 | | | $ | 5 | |
Interest expense on lease liability | | 12 | | 13 |
Total finance lease expense | | $ | 18 | | | $ | 18 | |
| | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2022 | | 2021 |
Operating leases | | | | |
PPA capacity payments | | $ | 182 | | | $ | 170 | |
Other operating leases (a) | | 28 | | | 19 | |
Total operating lease expense (b) | | $ | 210 | | | $ | 189 | |
Finance leases | | | | |
Amortization of ROU assets | | $ | 3 | | | $ | 6 | |
Interest expense on lease liability | | 12 | | | 12 | |
Total finance lease expense | | $ | 15 | | | $ | 18 | |
(a)Includes short-term lease expense of $4of $4 million for 20212022 and 2020, respectively.2021.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Sept. 30, 2021:2022:
| (Millions of Dollars) | (Millions of Dollars) | | PPA Operating Leases | | Other Operating Leases | | Total Operating Leases | | Finance Leases (a) | (Millions of Dollars) | | PPA Operating Leases | | Other Operating Leases | | Total Operating Leases | | Finance Leases (a) |
Total minimum obligation | Total minimum obligation | | $ | 1,470 | | | $ | 191 | | | $ | 1,661 | | | $ | 246 | | Total minimum obligation | | $ | 1,246 | | | $ | 166 | | | $ | 1,412 | | | $ | 239 | |
Interest component of obligation | Interest component of obligation | | (221) | | | (35) | | | (256) | | | (173) | | Interest component of obligation | | (174) | | | (30) | | | (204) | | | (169) | |
Present value of minimum obligation | Present value of minimum obligation | | $ | 1,249 | | | 156 | | | 1,405 | | | 73 | | Present value of minimum obligation | | $ | 1,072 | | | 136 | | | 1,208 | | | 70 | |
Less current portion | Less current portion | | (218) | | | (3) | | Less current portion | | (211) | | | (4) | |
Noncurrent operating and finance lease liabilities | Noncurrent operating and finance lease liabilities | | $ | 1,187 | | | $ | 70 | | Noncurrent operating and finance lease liabilities | | $ | 997 | | | $ | 66 | |
(a)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
VIEsVariable Interest Entities
Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the IPP.
The utility subsidiaries had approximately ma4,062tely 3,961 MW and 4,062 MW of capacity under long-term PPAs at both Sept. 30, 20212022 and Dec. 31, 20202021, respectively, with entities that have been determined to be VIEs.variable interest entities. Xcel Energy concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. The PPAs have expiration dates through 2041.
Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provideprovides guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the agreements. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of Sept. 30, 20212022 and Dec. 31, 2020,2021, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were approximately $60 million and $62 million and $60 million at Sept. 30, 20212022 and Dec. 31, 2020, respectively.2021, respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provideprovides indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.
Xcel Energy Inc.’s and its subsidiaries’Energy’s obligations under these agreements may be limited in duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated.
| | |
11. Other Comprehensive Income (Loss) |
Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 20212022 and 2020:2021:
| | | Three Months Ended Sept. 30, 2021 | | Three Months Ended Sept. 30, 2020 | | Three Months Ended Sept. 30, 2022 | | Three Months Ended Sept. 30, 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive loss at July 1 | Accumulated other comprehensive loss at July 1 | | $ | (80) | | | $ | (55) | | | $ | (135) | | | $ | (87) | | | $ | (58) | | | $ | (145) | | Accumulated other comprehensive loss at July 1 | | $ | (57) | | | $ | (46) | | | $ | (103) | | | $ | (80) | | | $ | (55) | | | $ | (135) | |
Other comprehensive gain before reclassifications (net of taxes of $1, $—, $— and $—, respectively) | | 3 | | | — | | | 3 | | | — | | | — | | | — | | |
Other comprehensive gain before reclassifications | | Other comprehensive gain before reclassifications | | — | | | 10 | | | 10 | | | 3 | | | — | | | 3 | |
Losses reclassified from net accumulated other comprehensive loss: | Losses reclassified from net accumulated other comprehensive loss: | | Losses reclassified from net accumulated other comprehensive loss: | |
Interest rate derivatives (net of taxes of $—, $—, $— and $—, respectively) (a) | 2 | | | — | | | 2 | | | 1 | | | — | | | 1 | | |
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) (b) | | — | | | 4 | | | 4 | | | — | | | 1 | | | 1 | | |
Interest rate derivatives (a) | | Interest rate derivatives (a) | 1 | | | — | | | 1 | | | 2 | | | — | | | 2 | |
Amortization of net actuarial loss (b) | | Amortization of net actuarial loss (b) | | — | | | 1 | | | 1 | | | — | | | 4 | | | 4 | |
Net current period other comprehensive income | Net current period other comprehensive income | | 5 | | | 4 | | | 9 | | | 1 | | | 1 | | | 2 | | Net current period other comprehensive income | | 1 | | | 11 | | | 12 | | | 5 | | | 4 | | | 9 | |
Accumulated other comprehensive loss at Sept. 30 | Accumulated other comprehensive loss at Sept. 30 | | $ | (75) | | | $ | (51) | | | $ | (126) | | | $ | (86) | | | $ | (57) | | | $ | (143) | | Accumulated other comprehensive loss at Sept. 30 | | $ | (56) | | | $ | (35) | | | $ | (91) | | | $ | (75) | | | $ | (51) | | | $ | (126) | |
| | | Nine Months Ended Sept. 30, 2021 | | Nine Months Ended Sept. 30, 2020 | | Nine Months Ended Sept. 30, 2022 | | Nine Months Ended Sept. 30, 2021 |
(Millions of Dollars) | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive loss at Jan. 1 | Accumulated other comprehensive loss at Jan. 1 | | $ | (85) | | | $ | (56) | | | $ | (141) | | | $ | (80) | | | $ | (61) | | | $ | (141) | | Accumulated other comprehensive loss at Jan. 1 | | $ | (75) | | | $ | (48) | | | $ | (123) | | | $ | (85) | | | $ | (56) | | | $ | (141) | |
Other comprehensive gain (loss) before reclassifications (net of taxes of $1, $—, $(3) and $—, respectively) | | 4 | | | — | | | 4 | | | (10) | | | — | | | (10) | | |
Other comprehensive gain before reclassifications | | Other comprehensive gain before reclassifications | | 15 | | | 11 | | | 26 | | | 4 | | | — | | | 4 | |
Losses reclassified from net accumulated other comprehensive loss: | Losses reclassified from net accumulated other comprehensive loss: | | Losses reclassified from net accumulated other comprehensive loss: | |
Interest rate derivatives (net of taxes of $1, $—, $1 and $—, respectively) (a) | | 6 | | | — | | | 6 | | | 4 | | | — | | | 4 | | |
Amortization of net actuarial loss (net of taxes of $—, $2, $— and $1, respectively) (b) | | — | | | 5 | | | 5 | | | — | | | 4 | | | 4 | | |
Net current period other comprehensive income (loss) | | 10 | | | 5 | | | 15 | | | (6) | | | 4 | | | (2) | | |
Interest rate derivatives (a) | | Interest rate derivatives (a) | | 4 | | | — | | | 4 | | | 6 | | | — | | | 6 | |
Amortization of net actuarial loss (b) | | Amortization of net actuarial loss (b) | | — | | | 2 | | | 2 | | | — | | | 5 | | | 5 | |
Net current period other comprehensive income | | Net current period other comprehensive income | | 19 | | | 13 | | | 32 | | | 10 | | | 5 | | | 15 | |
Accumulated other comprehensive loss at Sept. 30 | Accumulated other comprehensive loss at Sept. 30 | | $ | (75) | | | $ | (51) | | | $ | (126) | | | $ | (86) | | | $ | (57) | | | $ | (143) | | Accumulated other comprehensive loss at Sept. 30 | | $ | (56) | | | $ | (35) | | | $ | (91) | | | $ | (75) | | | $ | (51) | | | $ | (126) | |
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs.
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo.
These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits and the operations of MEC until July 2020.credits.
Xcel Energy had equity method investments of $204$214 million and $165$208 million as of Sept. 30, 20212022 and Dec. 31, 2020,2021, respectively, included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Xcel Energy’s segment information:
| | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 |
(Millions of Dollars) | | 2022 | | 2021 |
Regulated Electric | | | | |
| | | | |
| | | | |
Total revenues | | $ | 3,699 | | | $ | 3,176 | |
Net income | | 697 | | | 629 | |
Regulated Natural Gas | | | | |
Operating revenues | | $ | 357 | | | $ | 268 | |
Intersegment revenue | | 1 | | | 1 | |
Total revenues | | $ | 358 | | | $ | 269 | |
Net (loss) income | | (7) | | | 10 | |
All Other | | | | |
Total revenues | | $ | 26 | | | $ | 23 | |
Net loss | | (41) | | | (30) | |
Consolidated Total | | | | |
Total revenues | | $ | 4,083 | | | $ | 3,468 | |
Reconciling eliminations | | (1) | | | (1) | |
Total operating revenues | | $ | 4,082 | | | $ | 3,467 | |
Net income | | 649 | | | 609 | |
| | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2022 | | 2021 |
Regulated Electric | | | | |
Operating revenues | | $ | 9,255 | | | $ | 8,643 | |
Intersegment revenue | | 1 | | | 1 | |
Total revenues | | $ | 9,256 | | | $ | 8,644 | |
Net income | | 1,312 | | | 1,202 | |
Regulated Natural Gas | | | | |
Operating revenues | | $ | 1,923 | | | $ | 1,364 | |
Intersegment revenue | | 1 | | | 2 | |
Total revenues | | $ | 1,924 | | | $ | 1,366 | |
Net income | | 148 | | | 161 | |
All Other | | | | |
Total operating revenue | | $ | 79 | | | $ | 69 | |
Net loss | | (103) | | | (81) | |
Consolidated Total | | | | |
Total revenues | | $ | 11,259 | | | $ | 10,079 | |
Reconciling eliminations | | (2) | | | (3) | |
Total operating revenues | | $ | 11,257 | | | $ | 10,076 | |
Net income | | 1,357 | | | 1,282 | |
Xcel Energy’s segment information:
| | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 |
(Millions of Dollars) | | 2021 | | 2020 |
Regulated Electric | | | | |
Operating revenues — external | | $ | 3,176 | | | $ | 2,941 | |
Intersegment revenue | | — | | | 1 | |
Total revenues | | $ | 3,176 | | | $ | 2,942 | |
Net income | | 629 | | | 632 | |
Regulated Natural Gas | | | | |
Operating revenues — external | | $ | 268 | | | $ | 219 | |
Intersegment revenue | | 1 | | | — | |
Total revenues | | 269 | | | 219 | |
Net income | | 10 | | | — | |
All Other | | | | |
Total revenues | | $ | 23 | | | $ | 22 | |
Net loss | | (30) | | | (29) | |
Consolidated Total | | | | |
Total revenues | | $ | 3,468 | | | $ | 3,183 | |
Reconciling eliminations | | (1) | | | (1) | |
Total operating revenues | | $ | 3,467 | | | $ | 3,182 | |
Net income | | 609 | | | 603 | |
| | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2021 | | 2020 |
Regulated Electric | | | | |
Operating revenues — external | | $ | 8,643 | | | $ | 7,430 | |
Intersegment revenue | | 1 | | | 1 | |
Total revenues | | $ | 8,644 | | | $ | 7,431 | |
Net income | | 1,202 | | | 1,148 | |
Regulated Natural Gas | | | | |
Operating revenues — external | | $ | 1,364 | | | $ | 1,082 | |
Intersegment revenue | | 2 | | | 1 | |
Total revenues | | 1,366 | | | 1,083 | |
Net income | | $ | 161 | | | $ | 111 | |
All Other | | | | |
Total revenues | | 69 | | 67 |
Net loss | | $ | (81) | | | $ | (74) | |
Consolidated Total | | | | |
Total revenues | | $ | 10,079 | | | $ | 8,581 | |
Reconciling eliminations | | (3) | | | (2) | |
Total operating revenues | | $ | 10,076 | | | $ | 8,579 | |
Net income | | 1,282 | | | 1,185 | |
| | | | | | | | | | | | | | |
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales — other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries.
For the three and nine months ended Sept. 30, 20212022 and 2020,2021, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole.
Summarized diluted EPS for Xcel Energy:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
Diluted Earnings (Loss) Per Share | Diluted Earnings (Loss) Per Share | | 2021 | | 2020 | | 2021 | | 2020 | Diluted Earnings (Loss) Per Share | | 2022 | | 2021 | | 2022 | | 2021 |
PSCo | PSCo | | $ | 0.40 | | | $ | 0.42 | | | $ | 0.96 | | | $ | 0.87 | | PSCo | | $ | 0.45 | | | $ | 0.40 | | | $ | 1.02 | | | $ | 0.96 | |
NSP-Minnesota | NSP-Minnesota | | 0.46 | | | 0.46 | | | 0.91 | | | 0.89 | | NSP-Minnesota | | 0.49 | | | 0.46 | | | 0.94 | | | 0.91 | |
SPS | SPS | | 0.25 | | | 0.24 | | | 0.48 | | | 0.46 | | SPS | | 0.25 | | | 0.25 | | | 0.52 | | | 0.48 | |
NSP-Wisconsin | NSP-Wisconsin | | 0.07 | | | 0.08 | | | 0.15 | | | 0.16 | | NSP-Wisconsin | | 0.07 | | | 0.07 | | | 0.19 | | | 0.15 | |
Earnings from equity method investments — WYCO | Earnings from equity method investments — WYCO | | 0.01 | | | 0.01 | | | 0.03 | | | 0.04 | | Earnings from equity method investments — WYCO | | 0.01 | | | 0.01 | | | 0.03 | | | 0.03 | |
Regulated utility (a) | Regulated utility (a) | | 1.19 | | | 1.21 | | | 2.54 | | | 2.42 | | Regulated utility (a) | | 1.28 | | | 1.19 | | | 2.69 | | | 2.54 | |
Xcel Energy Inc. and Other | Xcel Energy Inc. and Other | | (0.06) | | | (0.07) | | | (0.16) | | | (0.17) | | Xcel Energy Inc. and Other | | (0.09) | | | (0.06) | | | (0.21) | | | (0.16) | |
Total (a) | Total (a) | | $ | 1.13 | | | $ | 1.14 | | | $ | 2.38 | | | $ | 2.25 | | Total (a) | | $ | 1.18 | | | $ | 1.13 | | | $ | 2.48 | | | $ | 2.38 | |
(a) Amounts may not add due to rounding.
Summary of Earnings
Xcel Energy — Xcel Energy’s GAAP third quarter diluted earnings were $1.18 per share in 2022 compared with $1.13 per share in 2021 compared with $1.14 per share in 2020 for the third quarter of 2021 and increased $0.13 per share year-to-date. Higher depreciation and lower AFUDC were2021. The increase was driven by regulatory rate outcomes, partially offset by higher depreciation, interest charges and O&M expenses. Costs for natural gas sold and transported significantly increased in 2022 primarily due to supply and demand conditions. However, fluctuations in electric and natural gas margins (drivenrevenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by capital investment recovery and other regulatory outcomes) and lower O&M expenses.the related variation in revenues).
PSCo — Earnings decreased $0.02increased $0.05 per share for the third quarter of 20212022 and increased $0.09 per share$0.06 year-to-date. The increase inHigher year-to-date earnings reflects higher natural gas and electric margins (regulatoryreflect regulatory rate outcomes, to primarily recover capital investments), partially offset by additional depreciation, O&M expenses and other taxes (other than income taxes).
NSP-Minnesota — Earnings were flat for the third quarter of 2021 and increased $0.02 per share year-to-date. The increase in year-to-date earnings reflects higher electric margin (regulatory outcomes to primarily recover capital investments), partially offset by increased depreciation and O&M expenses.
SPSNSP-Minnesota — Earnings increased $0.01$0.03 per share for the third quarter of 20212022 and $0.02year-to-date. The year-to-date increase is primarily due to regulatory rate outcomes, partially offset by increased depreciation, O&M expenses and a Winter Storm Uri cost disallowance.
SPS — Earnings were flat for the third quarter of 2022 and increased $0.04 per share year-to-date. The increase inHigher year-to-date earnings reflects higher electric margin (capital investment recoverylargely reflect regulatory rate outcomes, strong sales growth and regulatory outcomes),favorable weather, partially offset by decreased AFUDC.higher depreciation, O&M expenses and interest charges.
NSP-Wisconsin — Earnings decreased $0.01 per sharewere flat for the third quarter of 20212022 and $0.01increased $0.04 per share year-to-date. The decrease in year-to-date earningsincrease is largely driven by higher O&M expensesdue to regulatory rate outcomes and income tax expense,sales growth, partially offset by higher electric margindepreciation and lower depreciation.O&M expenses.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company and earnings from EIPEnergy Impact Partners funds equity method investments. Earnings decreased $0.05 per share year-to-date, largely attributable to higher interest charges.
Changes in GAAP and Ongoing Diluted EPS
Components significantly contributing to changes in 20212022 EPS compared to 2020:2021:
| | | | | | | | | | | | | | |
Diluted Earnings (Loss) Per Share | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
GAAP and ongoing diluted EPS — 2020 | | $ | 1.14 | | | $ | 2.25 | |
| | | | |
Components of change - 2021 vs. 2020 | | | | |
Higher electric margin | | 0.01 | | | 0.25 | |
Higher natural gas margins | | 0.03 | | | 0.15 | |
Lower ETR (a) | | 0.01 | | | 0.12 | |
Higher other (expense) income, net | | (0.01) | | | 0.02 | |
Lower interest charges | | 0.01 | | | — | |
Lower (Higher) O&M expenses | | 0.02 | | | (0.06) | |
Lower AFUDC | | (0.02) | | | (0.09) | |
Higher depreciation and amortization | | (0.03) | | | (0.19) | |
Other, net | | (0.03) | | | (0.07) | |
GAAP and ongoing diluted EPS — 2021 | | $ | 1.13 | | | $ | 2.38 | |
| | | | | | | | | | | | | | |
Diluted Earnings (Loss) Per Share | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
GAAP and ongoing diluted EPS — 2021 | | $ | 1.13 | | | $ | 2.38 | |
| | | | |
Components of change - 2022 vs. 2021 | | | | |
Higher electric revenues, net of electric fuel and purchased power | | 0.33 | | | 0.67 | |
Lower effective tax rate (ETR) (a) | | 0.02 | | | 0.12 | |
Higher natural gas revenues, net of cost of natural gas sold and transported | | — | | | 0.04 | |
Higher depreciation and amortization | | (0.10) | | | (0.30) | |
Higher O&M expenses | | (0.06) | | | (0.10) | |
Higher interest charges | | (0.04) | | | (0.10) | |
Higher taxes (other than income taxes) | | (0.03) | | | (0.07) | |
Lower other (expense) income | | (0.02) | | | (0.03) | |
Other, net | | (0.05) | | | (0.13) | |
GAAP and ongoing diluted EPS — 2022 | | $ | 1.18 | | | $ | 2.48 | |
(a)Includes PTCs and plant regulatory amounts, which are primarily offset inas a reduction to electric margin.revenues.
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings —Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, sales true-up and decoupling mechanisms in MinnesotaColorado and Coloradoproposed sales true-up mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather.weather for the electric utility in those jurisdictions.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.
Normal weather conditions are defined as either the 10, 20 or 30 year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD:HDD, CDD and THI:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 vs. Normal | | 2020 vs. Normal | | 2021 vs. 2020 | | 2021 vs. Normal | | 2020 vs. Normal | | 2021 vs. 2020 | | 2022 vs. Normal | | 2021 vs. Normal | | 2022 vs. 2021 | | 2022 vs. Normal | | 2021 vs. Normal | | 2022 vs. 2021 |
HDD | HDD | (50.5) | % | | 48.4 | % | | (65.8) | % | | 0.1 | % | | (2.8) | % | | 1.5 | % | HDD | (27.8) | % | | (50.5) | % | | 36.0 | % | | 8.3 | % | | 0.1 | % | | 7.5 | % |
CDD | CDD | 18.1 | | | 20.7 | | | (9.1) | | | 11.7 | | | 21.2 | | | (8.1) | | CDD | 23.0 | | | 18.1 | | | 13.0 | | | 24.7 | | | 11.7 | | | 17.8 | |
THI | THI | 6.2 | | | 4.6 | | | 2.4 | | | 25.5 | | | 7.0 | | | 18.7 | | THI | 1.7 | | | 6.2 | | | (4.2) | | | 6.4 | | | 25.5 | | | (14.4) | |
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
| | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 | | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
| | 2021 vs. Normal | | 2020 vs. Normal | | 2021 vs. 2020 | | 2021 vs. Normal | | 2020 vs. Normal | | 2021 vs. 2020 | | 2022 vs. Normal | | 2021 vs. Normal | | 2022 vs. 2021 | | 2022 vs. Normal | | 2021 vs. Normal | | 2022 vs. 2021 |
Retail electric | Retail electric | $ | 0.067 | | | $ | 0.079 | | | $ | (0.012) | | | $ | 0.122 | | | $ | 0.096 | | | $ | 0.026 | | Retail electric | $ | 0.074 | | | $ | 0.067 | | | $ | 0.007 | | | $ | 0.123 | | | $ | 0.122 | | | $ | 0.001 | |
Decoupling and sales true-up | Decoupling and sales true-up | (0.035) | | | (0.035) | | | — | | | (0.076) | | | (0.044) | | | (0.032) | | Decoupling and sales true-up | (0.032) | | | (0.035) | | | 0.003 | | | (0.055) | | | (0.076) | | | 0.021 | |
Electric total | Electric total | $ | 0.032 | | | $ | 0.044 | | | $ | (0.012) | | | $ | 0.046 | | | $ | 0.052 | | | $ | (0.006) | | Electric total | $ | 0.042 | | | $ | 0.032 | | | $ | 0.010 | | | $ | 0.068 | | | $ | 0.046 | | | $ | 0.022 | |
Firm natural gas | Firm natural gas | — | | | — | | | — | | | 0.004 | | | (0.005) | | | 0.009 | | Firm natural gas | — | | | — | | | — | | | 0.019 | | | 0.004 | | | 0.015 | |
Total | Total | $ | 0.032 | | | $ | 0.044 | | | $ | (0.012) | | | $ | 0.050 | | | $ | 0.047 | | | $ | 0.003 | | Total | $ | 0.042 | | | $ | 0.032 | | | $ | 0.010 | | | $ | 0.087 | | | $ | 0.050 | | | $ | 0.037 | |
Sales — Sales growth (decline) for actual and weather-normalized sales in 20212022 compared to 2020:2021:
| | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual | Actual | | | | | | | | | | | Actual | | | | | | | | | | |
Electric residential | Electric residential | | 0.4 | % | | 0.3 | % | | (7.8) | % | | (2.0) | % | | (1.0) | % | Electric residential | | (1.7) | % | | (2.7) | % | | 7.8 | % | | (0.1) | % | | (0.7) | % |
Electric C&I | Electric C&I | | 2.1 | | | 3.4 | | | 4.4 | | | 1.9 | | | 3.1 | | Electric C&I | | (2.3) | | | 0.2 | | | 7.2 | | | 3.7 | | | 1.6 | |
Total retail electric sales | Total retail electric sales | | 1.4 | | | 2.3 | | | 1.7 | | | 0.8 | | | 1.8 | | Total retail electric sales | | (2.0) | | | (0.8) | | | 7.3 | | | 2.6 | | | 0.9 | |
Firm natural gas sales | Firm natural gas sales | | (2.0) | | | (0.8) | | | N/A | | (7.8) | | | (2.0) | | Firm natural gas sales | | (1.6) | | | — | | | N/A | | 2.3 | | | (0.9) | |
| | | Three Months Ended Sept. 30 | | Three Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-Normalized | Weather-Normalized | | | | | | | | | | | Weather-Normalized |
Electric residential | Electric residential | | 2.2 | % | | (0.3) | % | | (1.4) | % | | 0.1 | % | | 0.5 | % | Electric residential | | (4.6) | % | | 0.5 | % | | 3.3 | % | | (0.1) | % | | (1.1) | % |
Electric C&I | Electric C&I | | 1.8 | | | 3.1 | | | 5.3 | | | 2.2 | | | 3.2 | | Electric C&I | | (3.2) | | | 0.4 | | | 6.4 | | | 3.5 | | | 1.2 | |
Total retail electric sales | Total retail electric sales | | 1.9 | | | 2.0 | | | 3.8 | | | 1.6 | | | 2.4 | | Total retail electric sales | | (3.7) | | | 0.4 | | | 5.9 | | | 2.5 | | | 0.5 | |
Firm natural gas sales | Firm natural gas sales | | 2.2 | | | 4.2 | | | N/A | | (4.6) | | | 2.4 | | Firm natural gas sales | | (1.5) | | | (2.2) | | | N/A | | — | | | (1.6) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual | | | | | | | | | | |
Electric residential | | 2.1 | % | | 3.5 | % | | (2.1) | % | | 1.7 | % | | 2.0 | % |
Electric C&I | | 1.0 | | | 2.1 | | | 1.5 | | | 3.6 | | | 1.7 | |
Total retail electric sales | | 1.4 | | | 2.5 | | | 0.8 | | | 3.0 | | | 1.8 | |
Firm natural gas sales | | 6.9 | | | (1.8) | | | N/A | | (0.9) | | | 3.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual | | | | | | | | | | |
Electric residential | | (2.9) | % | | (1.4) | % | | 4.9 | % | | 1.3 | % | | (0.9) | % |
Electric C&I | | (0.3) | | | 2.3 | | | 9.6 | | | 3.6 | | | 3.6 | |
Total retail electric sales | | (1.2) | | | 1.1 | | | 8.6 | | | 2.9 | | | 2.2 | |
Firm natural gas sales | | (3.4) | | | 19.9 | | | N/A | | 20.2 | | | 4.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-Normalized |
Electric residential | | 2.6 | % | | 0.9 | % | | 0.4 | % | | 0.4 | % | | 1.4 | % |
Electric C&I | | 0.9 | | | 1.4 | | | 2.0 | | | 3.2 | | | 1.5 | |
Total retail electric sales | | 1.5 | | | 1.2 | | | 1.7 | | | 2.4 | | | 1.5 | |
Firm natural gas sales | | 2.4 | | | (1.1) | | | N/A | | (1.0) | | | 1.0 | |
| | | Nine Months Ended Sept. 30 (2020 Leap Year Adjusted) | | Nine Months Ended Sept. 30 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-Normalized | Weather-Normalized | Weather-Normalized |
Electric residential | Electric residential | | 3.0 | % | | 1.2 | % | | 0.7 | % | | 0.8 | % | | 1.8 | % | Electric residential | | (3.7) | % | | 0.6 | % | | 0.7 | % | | 0.6 | % | | (1.0) | % |
Electric C&I | Electric C&I | | 1.3 | | | 1.8 | | | 2.4 | | | 3.6 | | | 1.9 | | Electric C&I | | (0.5) | | | 2.7 | | | 9.0 | | | 3.8 | | | 3.5 | |
Total retail electric sales | Total retail electric sales | | 1.9 | | | 1.6 | | | 2.0 | | | 2.7 | | | 1.9 | | Total retail electric sales | | (1.6) | | | 2.0 | | | 7.4 | | | 2.8 | | | 2.2 | |
Firm natural gas sales | Firm natural gas sales | | 3.2 | | | (0.3) | | | N/A | | (0.2) | | | 1.8 | | Firm natural gas sales | | (2.4) | | | 6.0 | | | N/A | | 7.4 | | | 0.9 | |
Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)
Weather-adjusted sales results for each of our utility subsidiaries in 2021 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated from pre-pandemic levels due to continuance of individuals working from home.
•PSCo — Residential sales rose based on a 1.2% increase in customers combined with higherdeclined due to decreased use per customer. The growth in C&I sales was due tocustomer, partially offset by a 1.1% increase in customers and slightly highercustomers. C&I sales decline was attributable to decreased use per customer, primarily in the manufacturing sector (largely due to an alternative generation arrangement with a significant customer), partially offset by strong small C&I sales in the professional services sector.and health care sectors.
•NSP-Minnesota — Residential sales growth reflects a 1.2% increase in customers. The growthcustomers, partially offset by decreased use per customer. Growth in C&I sales was primarily due to a 0.9% increase in customers and slightly higher use per customer, primarilyparticularly in the manufacturing, sector.real estate and leasing, and food service sectors.
•SPS — Residential sales rose based ongrowth was primarily attributable to a 0.8%1.0% increase in customers, despite slightlypartially offset by a lower use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — Residential sales growth was attributable todriven by a 0.8%0.7% increase in customer additions. The growth incustomers. C&I sales growth was due to a 1.1% increase in customers, primarily led by increasesassociated with higher use per customer, experienced primarily in the services sector.transportation and manufacturing sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)
•Natural gas sales primarily reflect a 1.2% increasehigher use per customer, experienced primarily in NSP-Minnesota and NSP-Wisconsin partially offset by a decrease in PSCo (lower residential customersuse per customer). In addition, residential and a 0.6% increase in C&I customers, combined with slightly higher customer use.growth was 1.2% and 0.5%, respectively.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue margin and income taxes.
Electric revenues, fuel and purchased power and margin and explanation of the changes are listed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2022 | | 2021 | | 2022 | | 2021 |
Electric revenues | | $ | 3,699 | | | $ | 3,176 | | | $ | 9,255 | | | $ | 8,643 | |
Electric fuel and purchased power | | (1,497) | | | (1,210) | | | (3,772) | | | (3,643) | |
Electric margin | | $ | 2,202 | | | $ | 1,966 | | | $ | 5,483 | | | $ | 5,000 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30, 2022 vs. 2021 | | Nine Months Ended Sept. 30, 2022 vs. 2021 |
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin) | | $ | 165 | | | $ | 361 | |
Revenue recognition for the Texas rate case surcharge (a) | | — | | | 85 | |
Sales and demand (b) | | 24 | | | 84 | |
| | | | |
Non-fuel riders | | 8 | | | 48 | |
Conservation and demand side management (offset in expenses) | | 9 | | | 31 | |
Wholesale transmission (net) | | 19 | | | 25 | |
Estimated impact of weather (net of decoupling/sales true-up) | | 7 | | | 16 | |
PTCs flowed back to customers (offset by lower ETR) | | (17) | | | (120) | |
Proprietary commodity trading, net of sharing (c) | | (1) | | | (33) | |
| | | | |
Other (net) | | 22 | | | (14) | |
Total increase | | $ | 236 | | | $ | 483 | |
(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs, see Public Utility Regulation for additional information.
(b)Sales excludes weather impact, net of decoupling in Colorado and proposed sales true-up mechanism in Minnesota.
(c)Includes $27 million of net gains recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri.
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas revenues, cost of natural gas sold and transported and margin and explanation of the changes are listed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2022 | | 2021 | | 2022 | | 2021 |
Natural gas revenues | | $ | 357 | | | $ | 268 | | | $ | 1,923 | | | $ | 1,364 | |
Cost of natural gas sold and transported | | (173) | | | (86) | | | (1,134) | | | (603) | |
Natural gas margin | | $ | 184 | | | $ | 182 | | | $ | 789 | | | $ | 761 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30, 2022 vs. 2021 | | Nine Months Ended Sept. 30, 2022 vs. 2021 |
Regulatory rate outcomes (Minnesota, Wisconsin, North Dakota, Colorado) | | $ | 2 | | | $ | 16 | |
Estimated impact of weather | | — | | | 11 | |
Conservation revenue (offset in expenses) | | 2 | | | 9 | |
Infrastructure and integrity riders | | 4 | | | 7 | |
Winter Storm Uri disallowances | | (7) | | | (20) | |
| | | | |
| | | | |
Other (net) | | 1 | | | 5 | |
Total increase | | $ | 2 | | | $ | 28 | |
Electric revenues and margin:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2021 | | 2020 | | 2021 | | 2020 |
Electric revenues | | $ | 3,176 | | | $ | 2,941 | | | $ | 8,643 | | | $ | 7,430 | |
Electric fuel and purchased power | | (1,210) | | | (981) | | | (3,643) | | | (2,611) | |
Electric margin | | $ | 1,966 | | | $ | 1,960 | | | $ | 5,000 | | | $ | 4,819 | |
Changes in electric margin:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30, 2021 vs. 2020 | | Nine Months Ended Sept. 30, 2021 vs. 2020 |
Non-fuel riders | | $ | 59 | | | $ | 196 | |
Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota) | | 30 | | | 106 | |
Proprietary commodity trading, net of sharing (a) | | 11 | | | 49 | |
| | | | |
Sales and demand (b) | | 10 | | | 20 | |
| | | | |
Estimated impact of weather (net of decoupling/sales true-up) | | (8) | | | (3) | |
| | | | |
Texas 2019 rate case surcharge (c) | | (70) | | | (70) | |
PTCs flowed back to customers (offset by lower ETR) | | (31) | | | (111) | |
Other (net) | | 5 | | | (6) | |
Total increase in electric margin | | $ | 6 | | | $ | 181 | |
(a)Includes $27 million of net gains previously recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri. Additional amounts are primarily related to long-term physical generation contracts, which have increased in value as a result of higher energy prices.
(b)Sales excludes weather impact, net of decoupling/sales true-up, and demand is net of sales true-up.
(c)Impact to electric margin is due to the Texas rate case outcome, which was recognized in the third quarter of 2020 and was largely offset by recognition of previously deferred costs.
Natural Gas Margin
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal impact on natural gas margin due to cost recovery mechanisms.
Natural gas revenues and margin:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended Sept. 30 | | Nine Months Ended Sept. 30 |
(Millions of Dollars) | | 2021 | | 2020 | | 2021 | | 2020 |
Natural gas revenues | | $ | 268 | | | $ | 219 | | | $ | 1,364 | | | $ | 1,082 | |
Cost of natural gas sold and transported | | (86) | | | (54) | | | (603) | | | (425) | |
Natural gas margin | | $ | 182 | | | $ | 165 | | | $ | 761 | | | $ | 657 | |
Changes in natural gas margin:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30, 2021 vs. 2020 | | Nine Months Ended Sept. 30, 2021 vs. 2020 |
Regulatory rate outcomes (Colorado) | | $ | 13 | | | $ | 84 | |
Infrastructure and integrity riders | | 3 | | | 7 | |
Estimated impact of weather | | (1) | | | 7 | |
| | | | |
| | | | |
Other (net) | | 2 | | | 6 | |
| | | | |
| | | | |
Total increase in natural gas margin | | $ | 17 | | | $ | 104 | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $11increased $43 million or 1.9%, for the third quarter and increased $44$75 million or 2.6% year-to-date. Significant changes are summarized as follows:
| | | | | | | | | | | | | | |
| | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30, 2021 vs. 2020 | | Nine Months Ended Sept. 30, 2021 vs. 2020 |
Wind | | $ | 14 | | | $ | 36 | |
Information technology and security | | 3 | | | 20 | |
Distribution | | 9 | | | 16 | |
Bad debt expense - PSCo settlement (See Note 1 to the consolidated financial statements) | | 11 | | | 11 | |
Natural gas systems | | (4) | | | 5 | |
Texas rate case deferral (offset in electric margin) | | (17) | | | (14) | |
Benefits | | (24) | | | (31) | |
Other | | (3) | | | 1 | |
Total (decrease) increase in O&M expenses | | $ | (11) | | | $ | 44 | |
The year-to-date increase was primarilyO&M costs increased due to expenses associated with new wind farms, software infrastructure and security costs, additional distribution expenses (vegetation management), bad debt expenserecognition of previously deferred amounts related to the PSCo settlement2021 Texas Electric Rate Case, additional investments in technology and natural gas damage prevention. Increasescustomer programs, higher costs for storms and vegetation management and inflationary impacts. These increases were partially offset by recognitiona reduction in employee benefit costs and timing of previous deferrals for Texas rate case activity in 2020 (offset in electric margin) and a decrease in benefits expense (primarily related to long term incentives). Quarterly timing impacts also occurred throughout 2020 due to cost control initiatives to mitigate the adverse impact of COVID-19 on sales.certain power plant overhaul costs.
Depreciation and Amortization — Depreciation and amortization increased $24$70 million or 4.7%, for the third quarter and $137$221 million or 9.5% year-to-date. The increase was primarily driven by normal system expansion, recognition of previously deferred costs related to the Texas Electric Rate Case and several wind farms going into service, normal system expansion and the implementation of new depreciation rates in various states. In addition, depreciation for the third quarter of 2020 reflected the recognition of previously deferred expenses associated with the Texas rate case.service.
Other (Expense) Income— Other (expense) income decreased $4$12 million for the third quarter and increased $11$25 million year-to-date. Changes wereyear-to-date, largely related to fluctuations in rabbi trust performance, which is primarily offset in O&M expenses.
AFUDC, Equity and Debt — AFUDC decreased $13 million for the third quarter of 2021 and $53 million year-to-date. The decrease was primarily driven by completion of various wind projects.expenses (employee benefit costs).
Interest Charges — Interest charges decreased $10increased $33 million or 4.5%, for the third quarter and were flat year-to-date. The quarter-to-date decrease was$77 million year-to-date, largely due to the timing of interest deferrals associated with the Texas rate case and lowerhigher interest rates partially offset by higherand increased long-term debt levels primarily due to Winter Storm Uri.fund capital investments.
Earnings from Equity Method InvestmentsIncome Taxes — — Earnings from equity method investmentsIncome tax expense increased $1 million for the third quarter and $18income tax benefit increased $63 million year-to-date. The year-to-date increase was largely attributable to the performance of the EIP funds, which invest in energy technology companies.
Income Taxes — Income tax benefit increased $41 million year-to-date. The increase was primarily driven by an increase in wind PTCs due to additionalgreater production at existing wind facilitiesfarms, several new wind farms going into service.service and an increase in the PTC rate. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. Impact of PTCs was partially offset by an increase in pretax earnings, lower plant regulatory differences, a carryback tax benefit in 2020 and lower non-plant accumulated deferred income tax amortization.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $985 million (largely deferred as regulatory assets) in the first quarter.
Regulatory Overview —Xcel Energy has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February cost increases for future recovery and are proposing to recover the cost increases over a period of up to 30 months to mitigate the impact to customer bills. Additionally, we are not requesting recovery of financing costs in order to further limit the impact to our customers.
Proceedings initiated:
| | | | | | | | |
Utility Subsidiary | Jurisdiction | Regulatory Status |
NSP-Minnesota | Minnesota | NSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. The DOC recommended disallowances of $21 million related to the utilization of natural gas storage. The OAG recommended disallowances of $34 million based on: (1) utilization of natural gas storage; (2) failure to enter fixed-price contracts; (3) failure to maximize curtailments to interruptible customers; and (4) inadequate conservation efforts to reduce demand. In addition, intervenors raised questions regarding peaking plant availability.
In August 2021, the MPUC allowed the utilities to start recovery of all Uri storm costs starting in September 2021 over 27 months (no financing charge). The cost recovery will be subject to refund pending the outcome of a contested case before an ALJ that will consider the DOC/OAG recommendations and issues related to the peaking plants. A decision is expected in the summer of 2022. |
| South Dakota | Winter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the electric market. |
| North Dakota | In June, the NDPSC approved recovery of $32 million in natural gas costs over 15 months (starting July 2021) with no financing charge. |
NSP-Wisconsin | Wisconsin | In March, the PSCW approved NSP-Wisconsin’s proposal to recover $45 million of Uri natural gas costs over nine months through December 2021 with no financing charge. |
| Michigan | In May, the Michigan Public Service Commission approved recovery of $2 million in natural gas costs over 10 months with no financing charge. |
| | | | | | | | |
Utility Subsidiary | Jurisdiction | Regulatory Status |
PSCo | Colorado | In May, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental gas costs and $4 million in incremental steam costs over 24 months with no financing charge.
In September, intervenors filed testimony. The CPUC Staff recommended disallowances of approximately $99 million (electric) and $105 million (natural gas). Additionally, they proposed to net approximately $50 million of regulatory liabilities (decoupling related) from electric costs. The UCA recommended disallowances of approximately $131 million. The COEO recommended disallowances of approximately $46 million for not utilizing demand response programs during the event. In October, a partial settlement was reached with the CPUC Staff and the COEO. See Note 1 of the accompanying consolidated financial statements for further discussion.
A decision is expected in the first quarter of 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery. |
SPS | Texas | As part of the Texas fuel surcharge filing, SPS filed for recovery of $76 million, over 24 months, in under-collected purchased power and fuel costs through March 2021, subject to revision due to re-settlements. Of this amount, $62 million was attributed to Winter Storm Uri.
In the third quarter, SPS filed a supplemental application and testimony to recover an additional $26 million in under-collected purchased power and fuel costs through June 2021 resulting primarily from SPP resettlements and continued increases in natural gas prices. The proposed recovery remains over 24 months beginning in February 2022.
In October 2021, intervenors proposed a $10 million disallowance of Winter Storm Uri off-system sales margin in addition to recommending an extended recovery period. A public hearing is scheduled to begin on Nov. 1, 2021, with a final PUCT decision expected in early 2022. |
| New Mexico | The NMPRC approved SPS' request to recover $26 million of fuel costs over 24 months with no financing charge, subject to NMPRC review. |
COVID-19
Although the COVID-19 pandemic has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will continue to allow us to proactively manage and successfully navigate challenges, risks and uncertainties.
Continued uncertainty remains regarding COVID-19, the pace of economic recovery, any potential re-shutdowns or reinstatement of business restrictions both domestically and globally and potential workforce impacts resulting from federal laws regarding vaccinations.
An overview of certain risk considerations or areas which have or could significantly impact us is as follows:
Sales — Xcel Energy has experienced and may continue to experience sales volatility and shifts between residential and C&I sales as a result of COVID-19. Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand small C&I electric classes), which mitigate the impact of changes to sales levels as compared to a baseline.
Bad Debt — Bad debt expense could significantly increase due to pandemic related economic impacts, customer hardship, federal or state legislation and regulatory orders. However, several of our commissions have approved the deferral of incremental COVID-19 related costs, including bad debt expense.
Xcel Energy has received orders in Colorado, Wisconsin, Texas, New Mexico, North Dakota, South Dakota and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Through the Minnesota electric rate case stay-out, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related costs. As part of the approved North Dakota electric rate case settlement agreement, the Company will not defer COVID-19 impacts. The impact related to the North Dakota natural gas utility will continue to be deferred.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed bad debt expense related to COVID-19 in Colorado. See Note 1 of the accompanying consolidated financial statements for further discussion.
The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve.
Supply Chain and Capital Expenditures— Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Overall, as a result of COVID-19, manufacturing processes have experienced disruptions related to scarcity of raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, storms and labor shortages. Xcel Energy continues to monitor the availability of materials and seek alternative suppliers as necessary.
| | |
Public Utility Regulation and Other |
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSMdemand side management efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.
Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020 and in Item 2 of Xcel Energy’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2021 and Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2021 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference. NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | |
Proceeding | | Amount (in millions) | | Filing Date | | Approval |
2020 TCR Electric Rider | | $82 | | November 2019 | | Pending |
2021 GUIC Natural Gas Rider | | 27 | | October 2020 | | Pending |
2021 RES Electric Rider | | 189 | | November 2020 | | Pending |
2020 North Dakota Electric Rate Case | | 19 | | November 2020 | | Received |
2021 North Dakota Natural Gas Rate Case | | 7 | | September 2021 | | Pending |
2022 Minnesota Electric Rate Case | | 677 | | October 2021 | | Pending |
2022 Minnesota Natural Gas Rate Case | | TBD | | November 2021 | | Pending |
Additional Information:
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider based on a ROE of 9.06%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider based on a ROE of 9.04%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount includes a true-up (2019 and 2020 riders) of $96 million and the 2021 requested amount of $93 million. The filing included a ROE of 9.06%. An MPUC decision is pending.
2020 North Dakota Electric Rate Case —In November 2020, In October 2021, NSP-Minnesota filed a three-year electric rate case with the NDPSC seekingMPUC. The rate case is based on a requested ROE of 10.2%, a 52.5% equity ratio and forward test years.
The request is detailed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(Amounts in Millions, Except Percentages) | | 2022 | | 2023 | | 2024 | | Total |
Annual rate increase requested | | $ | 396 | | | $ | 150 | | | $ | 131 | | | $ | 677 | |
Increase percentage | | 12.2 | % | | 4.8 | % | | 4.2 | % | | 21.2 | % |
Rate base | | $ | 10,931 | | | $ | 11,446 | | | $ | 11,918 | | | N/A |
In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. On Sept. 30, 2022, NSP-Minnesota requested an incremental increase to interim rates of $122 million, effective Jan. 1, 2023. On Oct. 21, 2022, intervening parties to the rate case filed comments recommending the MPUC deny NSP-Minnesota’s request. A MPUC decision is expected in late 2022.
In October 2022, nine parties filed testimony. The DOC, OAG, XLI, CUB and JSC were the only parties to quantify recommended financial adjustments. XLI recommended $112 million in proposed adjustments, based on reducing ROE, reducing recovery of incentive compensation and not including the prepaid pension asset in rate base. CUB recommended adjustments based on reducing ROE. Other parties provided specific issue recommendations.
Proposed DOC modifications to NSP-Minnesota’s request:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2022 | | 2023 | | 2024 |
NSP-Minnesota’s filed base revenue request | | $ | 396 | | | $ | 546 | | | $ | 677 | |
| | | | | | |
Recommended adjustments: | | | | | | |
Rate base and rate of return (a) | | (71) | | | (58) | | | (57) | |
MISO capacity credits | | (55) | | | (94) | | | (94) | |
Monticello and wind farm life extension | | (21) | | | (54) | | | (51) | |
PTC and ND ITC forecast | | (28) | | | (40) | | | (43) | |
Property tax | | (14) | | | (22) | | | (32) | |
Prepaid pension asset and liability | | (13) | | | (21) | | | (32) | |
O&M expenses | | (18) | | | (26) | | | (29) | |
Other, net | | (48) | | | (57) | | | (65) | |
| | | | | | |
Total adjustments | | (268) | | | (372) | | | (403) | |
Total proposed revenue change | | $ | 128 | | | $ | 174 | | | $ | 274 | |
(a)Included in the rate base and rate of return adjustments is an annual proposed increase in the cost of debt.
Positions on NSP-Minnesota’s filed rate request:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Recommended Position | | DOC | | XLI | | CUB | | JSC |
ROE | | 9.25 | % | | 9.17 | % | | 8.80-9.00 % | | 9.06 | % |
Equity | | 52.5 | % | | N/A | | N/A | | N/A |
Next steps in the procedural schedule are expected to be as follows:
•Rebuttal testimony: Nov. 8, 2022.
•Hearing: Dec. 13-16, 2022.
•ALJ Report: March 31, 2023.
•MPUC Order: June 30, 2023.
2022 Minnesota Natural Gas Rate Case—In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $19$36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.2%10.5%, an equity ratio of 52.5% and a rate base of $677$934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.
In August 2021, the NDPSC approved a settlement betweenOctober 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following effective Jan. 1, 2021:key terms:
•Base rate revenue increase of $7 million.$21 million, with a true up to weather normalized actual sales for 2022.
•Revenue decoupling mechanism.
•Symmetrical property tax true-up.
•ROE of 9.5%9.57%.
•Equity ratio of 52.5%.
•DeferralA hearing is scheduled for the fourth quarter of advanced grid intelligence2022 and security initiative capital and O&M expenses.
•An earnings cap mechanism, which would return to customers 100%a MPUC order is expected in the first half of earnings equal to or in excess of 9.75% ROE, effective until the next rate case.2023.
2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.49%10.5%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a rate base of approximately $140$124 million. NSP-Minnesota requested interimInterim rates of $7 million, subject to refund, of $7 million to bewere implemented on Nov. 1, 2021.
In May 2022, NSP-Minnesota and NDPSC Staff reached a natural gas settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio. A NDPSC decision is pending.
2022 MinnesotaSouth Dakota Electric Rate Case — On Oct. 25, 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The request is driven by ongoing investments in carbon free electrical generation, distribution and transmission infrastructure. The rate case is based on a requested ROE of 10.2% and a 52.50% equity ratio.
The request is detailed as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(Amounts in Millions, Except Percentages) | | 2022 | | 2023 | | 2024 | | Total |
Rate request | | $ | 396 | | | $ | 150 | | | $ | 131 | | | $ | 677 | |
Increase percentage | | 12.2 | % | | 4.8 | % | | 4.2 | % | | 21.2 | % |
Rate base | | $ | 10,931 | | | $ | 11,446 | | | $ | 11,918 | | | N/A |
In addition, NSP-Minnesota requested interim rates, subject to refund, of $288 million to be implemented in January 2022 and an incremental $135 million to be implemented in January 2023. To mitigate the interim increase, NSP-Minnesota also proposed to continue a sales true-up for all customer classes in both 2022 and 2023. This would result in interim rates, subject to refund, of $190 million to be implemented in January 2022 and an incremental $116 million to be implemented in January 2023. A final MPUC decision on the rate case is anticipated in the second quarter of 2023.
2022 Minnesota Natural Gas Rate Case—NSP-Minnesota plans to file a request with the MPUC for an annual natural gas rate case in November 2021. As part of the request, NSP-Minnesota plans to file an option for a one-year stay-out alternative.
Minnesota Resource Plan — In July 2019,June 2022, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034.
In Junea South Dakota electric rate case (first since 2014) seeking a revenue increase of approximately $44 million. The filing is based on a 2021 NSP-Minnesota filedhistoric test year adjusted for certain known and measurable changes for 2022 and 2023, a requested ROE of 10.75%, rate base of approximately $947 million and an alternative plan that would beequity ratio of 53%. Final rates are expected to reduce carbon emissions 85% by 2030 and has a lower projected cost than eitherbe effective in the first quarter of the previously submitted plans. The alternative plan includes the following:
•Removing the planned Sherco combined cycle natural gas plant.2023.
•Retiring all coal generation by 2030 with reduced operations at some units prior to retirement, including early retirement of the A.S. King coal plant (511 MW) in 2028 and Sherco 3 coal plant (517 MW) in 2030.
•Extending the life of the Monticello nuclear plant from 2030 to 2040.
•Continuing to run the Prairie Island nuclear generating plant at least through current end of life (2033 and 2034).
•Adding 3,150 MW of universal solar, 2,650 MW of wind and 250 MW of storage.
•Adding 800 MW of new hydrogen-ready combustion-turbines and repowering 300 MW of blackstart combustion-turbines.
•Adding 1,900 MW of other firm dispatchable resources.
•Constructing 155 miles of transmission lines.
•Achieving 780 gigawatt hours in energy efficiency savings annually through 2034.
•Adding 400 MW of incremental demand response by 2023 and a total of 1,500 MW of demand response by 2034.
The MPUC is anticipated to make a final decision in late 2021 or early 2022.
Minnesota Relief and RecoveryWind Repowering — In 2020, the MPUC opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19. The status of the various proposals is listed below:
•In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and 20other changes result in a levelized cost of energy that is approximately 30% lower than the original approval. In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects.
Wind PPA Buyout — In July 2022, NSP-Minnesota requested approval from the MPUC for updated agreements with ALLETE Clean Energy to purchase the repowered 100 MW Northern Wind Facility and 22 MW Rock Aetna Facility. In October 2022, the MPUC approved NSP-Minnesota’s updated acquisition agreements, which included an increase in the purchase price. The price increase is more than offset by the passage of wind projects under PPAs. These projects are estimatedthe IRA, resulting in greater savings for customers than the original approval.
2022 Minnesota Electric Vehicle Proposal — In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to save customers approximately $160 million over the next 25 years.support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs. A MPUC decision is expected in 2023.
•Sherco Solar Proposal — In April 2021, NSP-Minnesota proposedSeptember 2022, the MPUC approved NSP-Minnesota’s proposal to add 460 MWsMW of solar facilities at the Sherco site withsite. The project is expected to cost approximately $690 million (two phases to be completed in 2024 and 2025). As a result of the IRA, the levelized cost of the project is expected to be approximately 30% lower than previously estimated.
2022 RES Electric Rider — In November 2021, NSP-Minnesota filed the RES Rider. In September 2022, the MPUC approved the requested amount of $264 million, which includes a true-up (2020 and 2021 riders) of $154 million and the 2022 requested amount of $110 million.
2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the GUIC Rider for an incremental investmentamount of approximately $575$27 million. A MPUC decision is expected in early 2022.pending.
•2021 GUIC Natural Gas Rider — In June 2021,October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million. A MPUC approved NSP-Minnesota’s proposal to acquire a 120 MW repowered wind farm from ALLETE for $210 million.decision is pending.
•2022 TCR Electric Rider — TheIn November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million. A MPUC decision is also considering NSP-Minnesota’s revised proposal to provide $40 million of incremental electric vehicle rebates.pending.
Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020,2021 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020,2021, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference. NSP-WisconsinPSCo
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | |
Proceeding | | Amount (in millions) | | Filing Date | | Approval |
Electric and Natural Gas Settlement | | $66 | | July 2021 | | Pending |
Michigan Rate Case | | $2.5 | | September 2021 | | Pending |
Additional Information:
Wisconsin Electric andColorado Natural Gas SettlementRate Case —In July 2021, NSP-WisconsinJanuary 2022, PSCo filed a request with the PSCWCPUC seeking approval of a rate case settlement with various intervenors for 2022-2023.
If approved, the settlement agreement wouldnet increase electric rates by $35 million (4.9%) for 2022 and an incremental $18 million increase (2.5%) for 2023. For theto retail natural gas utility, rates would increase by $10of $107 million. The total change to base rates is $215 million, (8.4%) for 2022 andwhich reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request is based on a 10.25% ROE, an incremental $3 million (2.3%) increase for 2023.
Key elements of the settlement include:
•ROE of 9.80% for 2022 and 10.00% for 2023.
•Equityequity ratio of 52.5% for both55.66% and a 2022 and 2023.current test year with a projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022.
•Returning $9Additionally, PSCo’s request includes step revenue increases of $40 million in various net regulatory liabilities(effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to offset customer impacts in 2023.continued capital investment.
•Deferring certain pension and other post-employment benefit expense in 2021 through 2023.
•Addressing COVID-19 deferral recovery inIn October 2022, the next rate case proceeding.
•Deferring potential changes in tax expenses due to changes in federal or state tax law in 2021 through 2023.
•Incorporating an earnings sharing mechanism for 2022 and 2023.
A PSCWCPUC issued a written decision is anticipated in the fourth quarter of 2021.
Michigan Electric Rate Case — In September 2021, NSP-Wisconsin filed a Michigan electric rate case seekingapproving a rate increase net of $2.5rider roll-ins of $64 million. The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million based onof incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. PSCo anticipates using a ROE of 10.2%9.2% and an equity ratio of 52.5%53.8%. The CPUC denied the 2023-2024 step increases.
PSCo
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | |
Proceeding | | Amount (in millions) | | Filing Date | | Approval |
PSIA Extension | | $9 | | February 2021 | | Received |
Electric Rate Case | | $470 | | July 2021 | | Pending |
Additional Information:
PSIA Rider Extension — In February 2021, PSCo requested to extend its PSIA rider for three years (through the end of 2024), which would recover $464 million in project costs over a three-year period. The extension is intended to allow for a wind down of the rider and transition of recovery of the projects included in the rider to base rates in 2025. In October 2021, the CPUC approved a settlement agreement with CPUC Staff and the COEO to allow the rider to end at the end of 2021, transfer the investments recovered under the rider to base rates January 1, 2022, and defer $9 million of depreciation expense and return on $143 million in project costs in 2022.
Colorado Electric Rate RequestPower Pathway Settlement — In JulyJune 2022, the CPUC issued a final written order issuing the CPCN for the Pathway Project. Key decisions include:
•The CPUC approved PSCo’s cost estimate of $1.7 billion and recovery through the transmission rider.
•The CPUC modified the PIMs proposed in the settlement agreement, which focused on cost controls, to add a separate mechanism to further incentivize timely delivery of the Pathway Project segments. The CPUC also increased the magnitude of the PIMs.
•The CPUC granted conditional approval for the 345 kilovolt May Valley-Longhorn line extension, pending the level of renewables being added in that region through PSCo’s resource plan. The initial cost estimate for the extension is approximately $250 million.
Colorado Resource Plan Settlement— In August 2022, the CPUC issued a written approval of a revised settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo expects to commence the request for proposal process for generation resources and file a recovery method docket in the fourth quarter of 2022.
Key settlement terms include:
•Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).
•Conversion of the Pawnee coal plant to natural gas by no later than Jan. 1, 2026.
•Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025.
•Addition of ~2,400 MW of wind.
•Addition of ~1,600 MW of universal-scale solar.
•Addition of 400 MW of storage.
•Addition of 1,300 MW of flexible, dispatchable generation.
•Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.
Colorado Partial Settlement — In October 2021, PSCo filed a requestcomprehensive settlement with the CPUC seeking a net electric rate increaseStaff and the Colorado Energy Office, which proposed to address four outstanding regulatory items, including recovery of $343 million (or 12.4%). The total request reflects a $470 million increase, which includes $127 million of previously authorizedfuel costs currently recovered through various rider mechanisms. The request is based on a 10.0% ROE, an equity ratio of 55.64%, a 2022 forecast test year, a rate base of $10.3 billion and impacts of a new depreciation study. A historical test year was filed with arelated to Winter Storm Uri, disputed revenue deficiency of $404 million, including a 10.5% ROE. Rates are expected to be effective April 9, 2022.
| | | | | | | | |
Revenue Request (millions of dollars) | | 2022 |
Changes since 2019 rate case: | | |
Plant-related growth | | $ | 95 | |
Advanced grid intelligence and security | | 73 | |
Updated cost of capital | | 53 | |
New depreciation rates | | 43 | |
Wildfire mitigation | | 25 |
Property taxes | | 25 |
Amortization of previously approved deferrals | | 17 | |
Other | | 12 | |
Net increase to revenue | | 343 | |
Roll-in of previously authorized costs: | | |
TCA rider revenues and Cheyenne Ridge costs | | 127 | |
Total base revenue request | | $ | 470 | |
| | |
| | |
Expected average 2022 rate base (billions of dollars) | | $ | 10.3 | |
2019 Electric Rate Case Appeal — In August 2020, PSCo filed an appealassociated with the Denver District Court seeking a review of2020 electric decoupling pilot program year, replacement power costs associated with an extended outage at Comanche Unit 3 during 2020 and deferred customer bad debt balances associated with COVID-19. In July 2022, the CPUC decisions on gains and losses on sales of assets, oil and gas royalty revenues, Board of Directors equity compensation and a true-up surchargeapproved the settlement, with an $8 million disallowance relating to collect the difference between what rates should have been in place from February through August 2020 (based onthe CPUC’s decision on the Company’s Application for Reconsideration, Rehearing or Reargument) and what rates were actually in place. A decision is pending.Winter Storm Uri fuel costs.
Decoupling Filing — PSCo's 2019 Electric Rate Case includedPSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.
In April 2021, PSCo made its annual filing for 2020, and the revised tariff went into effect by operation of law on June 1, 2021. In the annual filing review, the CPUC indicated they may pursue reopening the case in order to revisit the cap. As of Sept. 30, 2021, PSCo has recognized a refund for Residential customers and a surcharge for C&I customers based on 2020 results and 2021 estimated amounts to date.
In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of decoupling. See Note 1Colorado Partial Settlement disclosure above.
As of Sept. 30, 2022, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021 and the first, second and third quarters of 2022 results.
In April 2022, PSCo made its annual filing. In May 2022, the UCA filed a protest raising issues relating to the Winter Storm Uri settlement and the soft cap components of the accompanying consolidated financial statementsdecoupling program. On May 25, 2022 the CPUC found merit in UCA’s protest, suspended PSCo’s advice letter and referred the matter to the ALJ. A hearing is expected to take place in the fourth quarter of 2022 and an ALJ recommendation is expected in the first quarter of 2023.
2019 Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gains and losses on sales of assets and other items. In January 2022, the court issued its decision that the CPUC’s approach to gains and losses on certain sales of assets was legally erroneous and confiscatory to PSCo and set aside and remanded the issue for further discussion.consideration. In October 2022, the CPUC approved PSCo’s proposed methodology to allocate gains and losses.
Colorado’s Power Pathway Transmission Expansion GCA NOPR— In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR matter and proposed a 2 step process aimed at 1) considering near term process changes to the GCA used by various utilities and 2) a longer term process to evaluate potential performance incentive GCA structures to be filed by Nov. 1, 2022. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration.
Natural Gas Planning NOPR — In October 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans as a means to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and related CPCN application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans. The CPUC staff will provide proposed rules in the fourth quarter of 2022.
SPS
Pending and Recently Concluded Regulatory Proceedings
2021 Texas Electric Rate Case — In 2021, SPS filed an electric rate case with the PUCT and its municipalities seeking an increase in base rates of approximately $140 million. In May 2022, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms:
•Base rate increase of $89 million effective retroactively to March 15, 2021.
•A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.
•Depreciation lives for Tolk accelerated to 2034 and Harrington coal assets accelerated to 2024.
In July 2022, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $85 million, substantially offset by the recognition of previously deferred costs. The impact of the retroactive amounts is as follows:
| | | | | | | | |
(Millions of Dollars) | | Nine Months Ended Sept. 30, 2022 |
Revenue surcharge accrual | | $ | 85 | |
Depreciation and amortization | | (43) | |
O&M expenses | | (16) | |
Interest expense | | (12) | |
Taxes other than income taxes | | (10) | |
Fuel and purchased power | | (2) | |
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Other
Supply Chain
Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. For example, availability of certain types of transformers has been significantly impacted and in some cases may result in delays in new customer connections as we work to address the shortage. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.
Advanced Metering Infrastructure Implementation
Supply chain issues associated with semi-conductors have delayed the availability of advanced infrastructure electric meters, which has led to a reduced number of meters deployed in 2022. Impacts to the 2023 deployment schedule are currently being evaluated.
Solar Resources
In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.
Since that time, an interim stay on tariffs has been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota which was recently approved by the MPUC and certain PPAs in PSCo which are pending regulatory approval.
Marshall Wildfire
In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines in the ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.
In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance.
In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In June 2022, Plaintiffs served the class action lawsuit. In July 2022, PSCo filed a Motion to Dismiss.
Comanche Unit 3 Outage —In late January 2022, PSCo experienced an outage at the Comanche Unit 3 coal plant.The plant returned to service in June 2022. PSCo will not seek recovery of the $10 million of incremental replacement power costs incurred during the outage, which reflects a true-up to final incurred costs in the third quarter of 2022.
MISO Capacity Credits — The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing and is expected to generate revenues of approximately $90 million in 2022 and approximately $60 million in 2023. During the three and nine months ended Sept. 30, 2022, the NSP System received approximately $40 million and $50 million, respectively, of capacity credits. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.
Inflation Reduction Act — In March 2021, PSCo filedAugust 2022, the IRA was signed into law.
Key provisions impacting Xcel Energy include:
•Extends current PTC and ITC for renewable technologies (e.g., wind and solar).
•Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.
•Creates a CertificatePTC for solar, clean hydrogen and nuclear.
•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.
•Allows companies to monetize or sell credits to unrelated parties.
Xcel Energy anticipates the IRA will drive approximately $500 million of Public Conveniencecustomer savings over the next 5 years for existing company owned renewable projects, assuming appropriate regulatory mechanisms and Necessitydevelopment of a market for the Power Pathway transmission project, proposing a 560-mile, 345 kilovolt double circuit transmission networksale of credits. The IRA will drive additional customer savings as Xcel Energy adds new renewable projects due to enable approximately 4,000-5,000 MW of renewable generation in eastern Colorado with an estimated cost of approximately $1.7 billion.
PSCo also presented anthe extension of the Power Pathway project into southeast Colorado, referredtax credits and transferability.
The IRA is expected to as the May Valley - Longhorn Extension ($0.3 billion). PSCo expects future filings for related network upgrades, voltage support and interconnection facilities, whichallow Xcel Energy to monetize tax credits more efficiently with the May Valley - Longhorn Extension,incremental benefits passed through to customers. Transferability provisions apply to eligible tax credits generated starting in 2023 for both new and existing facilities. Xcel Energy anticipates tax credit transferability from existing renewable projects will improve cash from operations by $1.8 billion (2023-2027), assuming constructive regulatory outcomes and the development of a market. Tax credit transferability has been included in our five-year financing plan and rate base projections.
The IRA creates a nuclear PTC beginning in 2024 that may also provide additional customer savings. The annual customer benefit from these PTCs could result in an incremental investmentrange from $0 to $200 million, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of $0.5 - $1.0 billion. A CPUC decision regarding the Power Pathway project,credits.
In addition, the IRA created a new corporate AMT. Xcel Energy does not anticipate AMT having a material cash impact based on current estimates and our interpretation of AMT application.
Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the May Valley - Longhorn Extension, is expected by February 2022.
KEPCO Filing —In September 2020, PSCo filed withavailability of renewable generation. The cold weather also affected the CPUCcountry’s supply and demand for approvalnatural gas. These factors contributed to terminateextremely high market prices for natural gas and electricity. As a solar PPA with KEPCO Solarresult of Alamosa, Inc.the extremely high market prices, Xcel Energy incurred net natural gas, fuel and establish a regulatory asset to recover transactionpurchased energy costs of approximately $41 million. However, the ALJ ruled against approval of the Termination Agreement. In July 2021, the CPUC upheld the ALJ’s recommended decision.
Electric Resource Plan —In March 2021, PSCo filed its 2021 Electric Resource Plan with the CPUC. The filing outlines the proposed future retirements/conversions of PSCo’s remaining coal plants and is expected to result in an 80% renewable fuel mix and an 85% carbon emissions reduction target by 2030 (from 2005 levels).
Major components of PSCo's proposed preferred plan include:
•Early retirement of Comanche Generating Station: Unit 3 in 2040 (currently 2070).
•Early retirement of Hayden Generating Station: Unit 1 in 2028 (currently 2030); Unit 2 in 2027 (currently 2036).
•Conversion of Pawnee Generating Station from coal to natural gas in 2028 with retirement in 2041.
•2,300 MW of wind power.
•1,600 MW of large-scale solar power.
•400 MW of energy storage.
•1,300 MW of flexible dispatchable resources (including natural gas).
The preferred plan proposes to create a$1 billion (largely deferred as regulatory asset to recover costs over their original depreciation lives for the Hayden power plant and the coal handling equipment at Pawnee. It also proposes the use of securitization to finance and recover the remaining book value and decommissioning costs for Comanche Unit 3 upon retirement in 2040.assets).
In October 2021, intervenors filed varying proposals related to Comanche Unit 3’s retirement dateXcel Energy has received recovery approval from all of our impacted states except for Texas, which is pending. A summary of pending and commencement of Comanche Unit 3 reduced operations.
A CPUC decision on the resource planrecently approved regulatory requests for Winter Storm Uri cost recovery is expected in the first quarter of 2022 with the competitive solicitation for resource additions expected in the second quarter 2022. Incremental generation system costs to meet carbon emission reduction targets are proposed to be recovered through a Clean Energy Plan Rider.
PSCo — Comanche Unit 3 — PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up, the unit experienced a loss of turbine oil, which damaged the unit. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo incurred replacement power costs of approximately $16 million during the outage.
In October 2020, the CPUC initiated a review of Comanche Unit 3’s performance. In March 2021, the CPUC Staff issued a report, which noted higher-than average outages and included criticisms of PSCo’s operations of Comanche Unit 3 over the last ten years. The report recommended thorough explanation of the future of Comanche Unit 3 operations in the next resource plan, performance standards for all company-owned generation and a review of outage and repair costs in the upcoming proceedings.
In October 2021, a comprehensive settlement on several regulatory issues was reached, which also addressed treatment of Comanche Unit 3 replacement power costs. See Note 1 of the accompanying consolidated financial statements for further discussion.
SPS
Pending and Recently Concluded Regulatory Proceedingslisted below.
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ProceedingUtility Subsidiary | Jurisdiction | Amount (in millions) | | Filing Date | | ApprovalRegulatory Status |
2021 New Mexico Electric Rate CaseNSP-Minnesota | Minnesota | In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period.
In May 2022, the ALJs found the Winter Storm Uri fuel costs were prudently incurred and recommended no disallowances.
In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance. |
PSCo | $62Colorado | | JuneIn May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.
| | Pending In May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs with the exception of an $8 million disallowance. |
2021 Texas Electric Rate CaseSPS | | $140Texas | | In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million. February 2021
| | In April 2022, interim rates designed to recover $121 million over 30 months were approved. The interim rate recovery does not address the prudence of costs nor the retention of approximately $10 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision. Pending
In July 2022, the intervenors filed recommendations in the Fuel Reconciliation proceeding. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins).
A recommendation from the ALJ is expected in the fourth quarter of 2022 and a final decision is anticipated in the first quarter of 2023. |
Additional Information:
2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC with a current requested base rate increase of approximately $84 million.
The request was based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%, an equity ratio of 54.72% and a retail rate base of approximately $1.9 billion.
In June 2021, SPS and various parties filed an uncontested comprehensive stipulation, which includes:
•Base rate revenue increase of $62 million.
•ROE of 9.35% for purposes of filings related to (1) the Hale and Sagamore wind projects; and (2) reconciliation of the settlement revenue requirement.
•Equity ratio of 54.72%.
•Increase in depreciation expense of $6 million. This includes a change in the depreciable lives of the Tolk power plant to 2032 and coal handling assets at the Harrington facility to 2024.
The stipulation is subject to NMPRC approval. A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.
2021 Texas Electric Rate Case— In February 2021, SPS filed an electric rate case with the PUCT and its municipalities. The current request is seeking an increase in base rates of approximately $140 million. SPS’ net rate increase to Texas customers is expected to be approximately $71 million, or 9.2%, as a result of the offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
The request is based on a ROE of 10.35%, an equity ratio of 54.60%, a rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020.
The request includes the effect of losing approximately 400 MW from a wholesale transmission customer and changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032) and coal handling assets at the Harrington facility (to 2024).
In October 2021, the scheduled hearings were abated to continue progress on a potential rate case settlement between SPS and various intervenors.
Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2022.
Affordable Clean EnergyAir Act
In July 2019,April 2022 the EPA adoptedproposed regulations under the Affordable"Good Neighbor" provisions of the Clean Air Act. The proposed rules establish an allowance trading program for NOx, potentially impacting Xcel Energy rule, which requires statesgenerating facilities in Minnesota, Texas and Wisconsin. Facilities without NOx controls will have to secure additional allowances, install NOx controls, or develop plans by 2022 for greenhouse gas reductions from coal-fired power plants. In January 2021,a strategy of operations that utilizes the U.S. Court of Appealsexisting allowance allocations. The EPA has indicated that it intends for the D.C. Circuit issued a decision vacating and remandingrule to be final by the Affordable Clean Energy rule. That decision would allowend of 2022 with initial applicability for 2023. While the EPA to proceed with alternatefinancial impacts of the proposed regulation of coal-fired power plants. If the new rules require additional investment,are uncertain, Xcel Energy believesanticipates that the cost of these initiatives or replacement generation wouldcosts will be recoverable through rates based on prior state commission practices.regulatory mechanisms.
Emerging Regulation
New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. CERCLA
PFAS are man-made chemicals foundthat are widely used in many consumer products thatand can persist and accumulatebio-accumulate in the environment. These chemicals have received heightened attention by environmental regulators. Increased regulationXcel Energy does not manufacture PFAS but because PFAS are so ubiquitous in products and the environment, it may impact our operations. In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA, specifically perfluorooctanoic acid and other emerging contaminants atperfluorooctanesulfonic acid. This proposed rule could result in new obligations for investigation and cleanup wherever PFAS are found to be present. The impact the federal, state,proposed regulation may have on electric and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. Xcel Energy will continue to monitor these regulatory developments and their potential impact on its operations.
The U.S. Congressgas utilities is currently discussing potential proposals that may impact federal tax law. Proposals are being made in conjunction with a bipartisan infrastructure bill and a larger reconciliation package. At this time, it is unknown what, if any, changes may ultimately occur. If the tax laws were changed and there was an increase in the federal tax rate, Xcel Energy would expect to defer the impact and ultimately recover the incremental tax expense from our customers consistent with precedent in the federal tax law change in 2017. As a result, we would not expect the impact of a change in the tax rate to have a material impact on our earnings.
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Derivatives, Risk Management and Market Risk |
We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform under the contracts underlying itsour derivatives, the contracts expose us to some credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and Xcel Energy’s ability to earn a return on short-term investments.
Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
Fair value of net commodity trading contracts as of Sept. 30, 2021:2022:
| | | Futures / Forwards Maturity | | Futures / Forwards Maturity |
(Millions of Dollars) | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value |
NSP-Minnesota (a) | NSP-Minnesota (a) | | $ | (8) | | | $ | (7) | | | $ | (1) | | | $ | (1) | | | $ | (17) | | NSP-Minnesota (a) | | $ | (8) | | | $ | (11) | | | $ | (6) | | | $ | (3) | | | $ | (28) | |
NSP- Minnesota (b) | NSP- Minnesota (b) | | 2 | | | 7 | | | (6) | | | 2 | | | 5 | | NSP- Minnesota (b) | | 6 | | | 4 | | | (1) | | | (2) | | | 7 | |
PSCo (a) | PSCo (a) | | 10 | | | 8 | | | 1 | | | 1 | | | 20 | | PSCo (a) | | 17 | | | 7 | | | 3 | | | 1 | | | 28 | |
PSCo (b) | PSCo (b) | | (30) | | | (43) | | | (4) | | | — | | | (77) | | PSCo (b) | | (50) | | | (21) | | | 1 | | | — | | | (70) | |
| | $ | (26) | | | $ | (35) | | | $ | (10) | | | $ | 2 | | | $ | (69) | | | $ | (35) | | | $ | (21) | | | $ | (3) | | | $ | (4) | | | $ | (63) | |
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| | Options Maturity |
(Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value |
NSP-Minnesota (b) | | $ | 1 | | | $ | — | | | $ | — | | | $ | 4 | | | $ | 5 | |
PSCo (b) | | 25 | | | 22 | | | — | | | — | | | 47 | |
| | $ | 26 | | | $ | 22 | | | $ | — | | | $ | 4 | | | $ | 52 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Options Maturity |
(Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | | Greater Than 5 Years | | Total Fair Value |
NSP-Minnesota (b) | | $ | 1 | | | $ | — | | | $ | — | | | $ | 14 | | | $ | 15 | |
PSCo (b) | | 28 | | | 7 | | | — | | | — | | | 35 | |
| | $ | 29 | | | $ | 7 | | | $ | — | | | $ | 14 | | | $ | 50 | |
(a) Prices actively quoted or based on actively quoted prices.
(b) Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the nine months ended Sept. 30:
| (Millions of Dollars) | (Millions of Dollars) | | 2021 | | 2020 | (Millions of Dollars) | | 2022 | | 2021 |
Fair value of commodity trading net contracts outstanding at Jan. 1 | Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (54) | | | $ | (59) | | Fair value of commodity trading net contracts outstanding at Jan. 1 | | $ | (33) | | | $ | (54) | |
Contracts realized or settled during the period | Contracts realized or settled during the period | | (35) | | | (9) | | Contracts realized or settled during the period | | (11) | | | (35) | |
Commodity trading contract additions and changes during the period | Commodity trading contract additions and changes during the period | | 72 | | | 10 | | Commodity trading contract additions and changes during the period | | 31 | | | 72 | |
Fair value of commodity trading net contracts outstanding at Sept. 30 | Fair value of commodity trading net contracts outstanding at Sept. 30 | | $ | (17) | | | $ | (58) | | Fair value of commodity trading net contracts outstanding at Sept. 30 | | $ | (13) | | | $ | (17) | |
At Sept. 30, 2022, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately $9 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $9 million. At Sept. 30, 2021, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately $23 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $23 million. At Sept. 30, 2020, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $14 million. Market price movements can exceed 10% under abnormal circumstances.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value onof the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
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(Millions of Dollars) | | Three Months Ended Sept. 30 | | VaR Limit | | Average | | High | | Low |
2021 | | $ | 1.9 | | | $ | 3.0 | | | $ | 1.5 | | | $ | 2.2 | | | $ | 0.9 | |
2020 | | 1.2 | | | 3.0 | | | 1.0 | | | 1.3 | | | 0.8 | |
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this widespread weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021. | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended Sept. 30 | | Average | | High | | Low |
2022 | | $ | 0.9 | | | $ | 1.7 | | | $ | 3.0 | | | $ | 0.8 | |
2021 | | 1.9 | | | 1.5 | | | 2.2 | | | 0.9 | |
Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 23% ofand has its 20212022 and 2023 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impactin various stages of processing in Canada, Europe and the United States. We will continue to monitor the evolving situation in Ukraine and its global impacts and will take necessary actions to ensure a secure supply of enriched nuclear material supplied from Russia. Long-term, through 2030,material. NSP-Minnesota is scheduled to take delivery of approximatelyapproximately 30% of its average enriched nuclear material requirements from these sources. NSP-Minnesota is able to manage nuclear fuel supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.Russia through 2030.
Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
At Sept. 30, 20212022 and 2020,2021, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pre-tax interest expense annually by approximately $18$3 million and $6$18 million, respectively.
See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’Energy’s interest rate derivatives.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting.
Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitormonitors these policies to reflect changes and scope of operations.
At Sept. 30, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $71 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $57 million. At Sept. 30, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $73 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $43 million. At Sept. 30, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $29 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $3 million.
Xcel Energy conducts credit reviews for all counterparties and employs credit risk control,controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.
Xcel Energy uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value.
The Company’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.
Commodity Derivatives — Xcel Energy monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Sept. 30, 2021.2022.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Sept. 30, 2021.2022.
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LIQUIDITY AND CAPITAL RESOURCES |
Cash Flows
Operating Cash Flows
| | | | | | | | |
(Millions of Dollars) | | Nine Months Ended Sept. 30 |
Cash provided by operating activities — 20202021 | | $ | 2,1741,579 | |
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Components of change — 20212022 vs. 20202021 | | |
Higher net income | | 9775 | |
Non-cash transactions (a) | | 69159 | |
Changes in working capital (b) | | 111 (79) | |
Changes in net regulatory and other assets and liabilities | | (872)1,433 | |
Cash provided by operating activities — 20212022 | | $ | 1,5793,167 | |
(a)Non-cash transactions applicable to net income (e.g., depreciation and amortization, nuclear fuel amortization, changes in deferred income taxes, allowance for equity funds used during construction, etc.).
(b)Working capital includes accounts receivable, accrued unbilled revenues, inventories, accounts payable, other current assets and other current liabilities.
Net cash provided by operating activities decreased $595increased $1,588 million for the nine months ended Sept. 30, 20212022 compared with the prior year. The decreaseincrease was primarily due to the deferral of net natural gas, fuel and purchased energy costs related to Winter Storm Uri (incurred/deferred) in the first quarter.quarter of 2021.
Investing Cash Flows
| | | | | | | | |
(Millions of Dollars) | | Nine Months Ended Sept. 30 |
Cash used in investing activities — 20202021 | | $ | (3,021)(3,065) | |
| | |
Components of change — 20212022 vs. 20202021 | | |
DecreasedIncreased capital expenditures | | 649 (293) | |
Sale of MEC in 2020 | | (684) | |
Other investing activities | | (9)37 | |
Cash used in investing activities — 20212022 | | $ | (3,065)(3,321) | |
Net cash used in investing activities increased $44$256 million for the nine months ended Sept. 30, 20212022 compared with the prior year. The decreaseincrease in capital expenditures was primarilylargely due to the purchase of MEC in January 2020, which was subsequently sold in July 2020.timing and normal/planned system expansion.
Financing Cash Flows
| | | | | | | | |
(Millions of Dollars) | | Nine Months Ended Sept. 30 |
Cash provided by financing activities — 20202021 | | $ | 1,4841,988 | |
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Components of change — 20212022 vs. 20202021 | | |
Higher net short-term debt issuancesrepayments | | 238 | |
Lower repayments of long-term debt | | 302 (2,010) | |
Higher dividends paid to shareholderslong-term debt issuances, net of repayments | | (60)43 | |
Higher proceeds from issuance of common stock | | 143 | |
| | |
Other financing activities | | 24 (59) | |
Cash provided by financing activities — 20212022 | | $ | 1,988105 | |
Net cash provided by financing activities increased $504decreased $1,883 million for the nine months ended Sept. 30, 20212022 compared with the prior year. The increasedecrease was primarily attributablerelated to the amount/timing of debt issuances and repayments partially attributable toassociated with Winter Storm Uri.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.
•In January 2021,2022, contributions of $125$50 million were made across four of Xcel Energy’s pension plans.
•In 2020,2021, contributions of $150$131 million were made across four of Xcel Energy’s pension plans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of thetheir revolving credit facility termination date for two additional one-year periods beyond the June 2024September 2027 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
As of Oct. 26, 2021, Xcel25, 2022, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
| (Millions of Dollars) | (Millions of Dollars) | | Credit Facility (a) | | Drawn (b) | | Available | | Cash | | Liquidity | (Millions of Dollars) | | Credit Facility (a) | | Drawn (b) | | Available | | Cash | | Liquidity |
Xcel Energy Inc. | Xcel Energy Inc. | | $ | 1,250 | | | $ | 427 | | | $ | 823 | | | $ | — | | | $ | 823 | | Xcel Energy Inc. | | $ | 1,500 | | | $ | 129 | | | $ | 1,371 | | | $ | 1 | | | $ | 1,372 | |
PSCo | PSCo | | 700 | | | 8 | | | 692 | | | 7 | | | 699 | | PSCo | | 700 | | | 264 | | | 436 | | | 3 | | | 439 | |
NSP-Minnesota | NSP-Minnesota | | 500 | | | 9 | | | 491 | | | 258 | | | 749 | | NSP-Minnesota | | 700 | | | 55 | | | 645 | | | 4 | | | 649 | |
SPS | SPS | | 500 | | | 55 | | | 445 | | | 2 | | | 447 | | SPS | | 500 | | | 67 | | | 433 | | | 1 | | | 434 | |
NSP-Wisconsin | NSP-Wisconsin | | 150 | | | — | | | 150 | | | 3 | | | 153 | | NSP-Wisconsin | | 150 | | | — | | | 150 | | | 3 | | | 153 | |
Total | Total | | $ | 3,100 | | | $ | 499 | | | $ | 2,601 | | | $ | 270 | | | $ | 2,871 | | Total | | $ | 3,550 | | | $ | 515 | | | $ | 3,035 | | | $ | 12 | | | $ | 3,047 | |
(a)Credit facilities expire in June 2024.September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Bilateral Credit Agreement
In April 2021,2022, NSP-Minnesota’s uncommitted $75 million bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Sept. 30, 2021, NSP-Minnesota’s2022, NSP-Minnesota had $50 million of outstanding letters of credit under the $75 million bilateral credit agreement were as follows:agreement.
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(Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
NSP-Minnesota | | $ | 75 | | | $ | 41 | | | $ | 34 | |
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:
•$1.251.5 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$500700 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
In addition, in February 2021, Xcel Energy Inc. entered into a $1.2 billion 364-Day Term Loan Agreement that matures Feb. 17, 2022. Xcel Energy has an option to extend through Feb. 16, 2023.
Short-term debt outstanding for Xcel Energy was as follows:
| (Amounts in Millions, Except Interest Rates) | (Amounts in Millions, Except Interest Rates) | | Three Months Ended Sept. 30, 2021 | | Year Ended Dec. 31, 2020 | (Amounts in Millions, Except Interest Rates) | | Three Months Ended Sept. 30, 2022 | | Year Ended Dec. 31, 2021 |
Borrowing limit | Borrowing limit | | $ | 4,300 | | | $ | 3,100 | | Borrowing limit | | $ | 3,550 | | | $ | 3,100 | |
Amount outstanding at period end | Amount outstanding at period end | | 1,747 | | | 584 | | Amount outstanding at period end | | 158 | | | 1,005 | |
Average amount outstanding | Average amount outstanding | | 1,742 | | | 1,126 | | Average amount outstanding | | 187 | | | 1,399 | |
Maximum amount outstanding | Maximum amount outstanding | | 1,857 | | | 2,080 | | Maximum amount outstanding | | 329 | | | 2,054 | |
Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.57 | % | | 1.45 | % | Weighted average interest rate, computed on a daily basis | | 2.51 | % | | 0.57 | % |
Weighted average interest rate at period end | Weighted average interest rate at period end | | 0.56 | | | 0.23 | | Weighted average interest rate at period end | | 3.40 | | | 0.31 | |
Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.
Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.
Capital Expenditures — Base capital expenditures and incremental capital forecasts for Xcel Energy for 20222023 through 20262027 are as follows:
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| | Base Capital Forecast (Millions of Dollars) |
By Regulated Utility | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2022 - 2026 Total |
PSCo | | $ | 1,930 | | | $ | 1,850 | | | $ | 2,070 | | | $ | 2,220 | | | $ | 1,860 | | | $ | 9,930 | |
NSP-Minnesota | | 2,250 | | | 2,030 | | | 1,830 | | | 2,130 | | | 2,010 | | | 10,250 | |
SPS | | 630 | | | 660 | | | 690 | | | 780 | | | 790 | | | 3,550 | |
NSP-Wisconsin | | 480 | | | 420 | | | 540 | | | 460 | | | 390 | | | 2,290 | |
Other (a) | | (10) | | | — | | | 10 | | | (30) | | | 10 | | | (20) | |
Total base capital expenditures | | $ | 5,280 | | | $ | 4,960 | | | $ | 5,140 | | | $ | 5,560 | | | $ | 5,060 | | | $ | 26,000 | |
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| | Base Capital Forecast (Millions of Dollars) |
By Function | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | 2022 - 2026 Total |
Electric distribution | | $ | 1,485 | | | $ | 1,600 | | | $ | 1,520 | | | $ | 1,605 | | | $ | 1,720 | | | $ | 7,930 | |
Electric transmission | | 1,105 | | | 1,220 | | | 1,575 | | | 1,965 | | | 1,555 | | | 7,420 | |
Electric generation | | 645 | | | 580 | | | 670 | | | 650 | | | 650 | | | 3,195 | |
Natural gas | | 655 | | | 670 | | | 695 | | | 660 | | | 660 | | | 3,340 | |
Other | | 725 | | | 545 | | | 450 | | | 340 | | | 450 | | | 2,510 | |
Renewables | | 665 | | | 345 | | | 230 | | | 340 | | | 25 | | | 1,605 | |
Total base capital expenditures | | $ | 5,280 | | | $ | 4,960 | | | $ | 5,140 | | | $ | 5,560 | | | $ | 5,060 | | | $ | 26,000 | |
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| | Base Capital Forecast (Millions of Dollars) |
By Regulated Utility | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2023 - 2027 Total |
PSCo | | $ | 2,140 | | | $ | 2,440 | | | $ | 2,550 | | | $ | 1,980 | | | $ | 2,190 | | | $ | 11,300 | |
NSP-Minnesota | | 2,000 | | | 2,400 | | | 2,530 | | | 2,200 | | | 2,580 | | | 11,710 | |
SPS | | 710 | | | 780 | | | 720 | | | 770 | | | 900 | | | 3,880 | |
NSP-Wisconsin | | 540 | | | 570 | | | 500 | | | 450 | | | 540 | | | 2,600 | |
Other (a) | | 10 | | | 10 | | | (30) | | | 10 | | | 10 | | | 10 | |
Total base capital expenditures | | $ | 5,400 | | | $ | 6,200 | | | $ | 6,270 | | | $ | 5,410 | | | $ | 6,220 | | | $ | 29,500 | |
(a)Other category includes intercompany transfers for safe harbor wind turbines.
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| | Base Capital Forecast (Millions of Dollars) |
By Function | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | 2023 - 2027 Total |
Electric distribution | | $ | 1,610 | | | $ | 1,790 | | | $ | 1,680 | | | $ | 2,000 | | | $ | 2,450 | | | $ | 9,530 | |
Electric transmission | | 1,280 | | | 1,650 | | | 1,890 | | | 1,690 | | | 1,900 | | | 8,410 | |
Electric generation | | 710 | | | 910 | | | 900 | | | 560 | | | 650 | | | 3,730 | |
Natural gas | | 740 | | | 730 | | | 760 | | | 650 | | | 680 | | | 3,560 | |
Other | | 780 | | | 840 | | | 570 | | | 510 | | | 540 | | | 3,240 | |
Renewables | | 280 | | | 280 | | | 470 | | | — | | | — | | | 1,030 | |
Total base capital expenditures | | $ | 5,400 | | | $ | 6,200 | | | $ | 6,270 | | | $ | 5,410 | | | $ | 6,220 | | | $ | 29,500 | |
The five-year capital forecast includes the proposed Colorado Pathway transmission expansion (approximately $1.7 billion), the proposed 460 MW Sherco solar facility (approximately $600 million) and the approved ALLETE wind repowering (approximately $210 million).
Additional capital investment inbase plan does not include any potential renewable generation assets approved in our Minnesota and Colorado resource plans or additional transmission may becapital needed to integrate new renewable generation additions in Colorado, beyond the Pathway project. We expect further clarification in the five-year forecast pending approvalsecond half of regulatory filings in Minnesota and Colorado. The approval of2023 after the proposedcommissions rule on the recommended resource plansplan portfolios, which could result in upincremental capital expenditures of approximately $2 to 2,000 MW$4 billion (assuming 50% ownership of renewable generation being needed between 2024 - 2026, resulting in potential capital expenditures estimated between $1.0 to $1.5 billion (assuming Xcel Energy were to own ~50% of the renewables)projects). Additionally, the associated $0.5 billion to $1.0 billion of network upgrades, voltage support and interconnection work related to the Colorado Power Pathway could also be needed during this five-year forecast depending on resource mix, location and timing. Any additional capital investment would likely be funded with approximately 50% equity and 50% debt.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.
Financing for Capital Expenditures through 20262027 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Current estimated financing plans of Xcel Energy for 20222023 through 2026:2027 (includes the impact of approximately $1.8 billion of tax credit transferability):
| | | | | | | | |
(Millions of Dollars) | | |
Funding Capital Expenditures | | |
Cash from operations (a) | | $ | 17,64020,540 | |
New debt (b) | | 7,1108,210 | |
Equity through the DRIP and benefit program | | 450425 | |
Other equity | | 800325 | |
Base capital expenditures 2022-20262023-2027 | | $ | 26,00029,500 | |
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Maturing Debt | | $ | 3,9003,800 | |
(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
20212022 Planned Financing Activity — During 2021,2022, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit programs.programs. In addition, Xcel Energy may issue $8002022, approximately $150 million inof equity underhas been issued through an at-the-market program. Xcel Energy Inc. and its utility subsidiaries issued or plan to issue the following:following long-term debt:
| Issuer | Issuer | | Security | | Amount | | Status | | Tenor | | Coupon | Issuer | | Security | | Amount | | | Tenor | | Coupon |
Xcel Energy | Xcel Energy | | Unsecured Bonds | | $ | 800 | million | | 2021 Q4 | | 5 Year/10 Year | | TBD | Xcel Energy | | Unsecured Senior Notes | | $ | 700 | million | | | 10 Year | | 4.60% |
PSCo | PSCo | | First Mortgage Bonds | | 750 | million | | Completed | | 10 Year | | 1.88 | % | PSCo | | First Mortgage Bonds | | 300 | million | | | 10 Year | | 4.10% |
PSCo | | PSCo | | First Mortgage Bonds | | 400 | million | | | 30 Year | | 4.50% |
SPS | SPS | | First Mortgage Bonds | | 250 | million | | Completed | | 29 Year | | 3.15 | | SPS | | First Mortgage Bonds | | 200 | million | | | 30 Year | | 5.15% |
NSP-Minnesota | NSP-Minnesota | | First Mortgage Bonds | | 425 | million | | Completed | | 10 Year | | 2.25 | | NSP-Minnesota | | First Mortgage Bonds | | 500 | million | | | 30 Year | | 4.50% |
NSP-Minnesota | | First Mortgage Bonds | | 425 | million | | Completed | | 31 Year | | 3.20 | | |
NSP-Wisconsin | NSP-Wisconsin | | First Mortgage Bonds | | 100 | million | | Completed | | 30 Year | | 2.82 | | NSP-Wisconsin | | First Mortgage Bonds | | 100 | million | | | 30 Year | | 4.86% |
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Financing plans are subject to change, depending on legislative initiatives (e.g., federal tax law changes), capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 20212022 Earnings Guidance — — Xcel Energy narrows 2021Energy’s 2022 GAAP and ongoing earnings guidance is a narrowed range of $3.14 to $2.94 to $2.98 from $2.90 to $3.00$3.19 per share.(a)
Key assumptions as compared with 20202021 levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Modest impacts from COVID-19.
•Normal weather patterns for the remainder of the year.
•Weather-normalized retail electric sales are projected to increase ~1.5 to 2%~2%.
•Weather-normalized retail firm natural gas sales are projected to increase ~1 to 2%~1%.
•Capital rider revenue is projected to increase $100 million to $110 millionbe relatively flat (net of PTCs). PTCs are creditedThe reduction in capital rider revenue is due to customers, through capital riders, fuel clause or base rateschanges in expected PTC levels and results in a reduction to electric margin.is largely earnings neutral.
•O&M expenses are projected to increase ~1%approximately 4%.
•Depreciation expense is projected to increase approximately $170$295 million to $180$305 million.
•Property taxes are projected to increase approximately $25$35 million to $35$45 million.
•Interest expense (net of AFUDC - debt) is projected to increase $20$100 million to $30$110 million.
•AFUDC - equity is projected to decline approximately $40 million to $50 million.be relatively flat.
•ETR is projected to be (4%~(7%) to (5%(9%). The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.
Xcel Energy 20222023 Earnings Guidance — Xcel Energy’s 20222023 GAAP and ongoing earnings guidance is a range of $3.10$3.30 to $3.20$3.40 per share.(a)
Key assumptions as compared with 20212022 projected levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to be relatively flat.
•Capital rider revenue is projected to increase $30$70 million to $40$80 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.
•O&M expenses are projected to increase approximately 1%.be relatively flat.
•Depreciation expense is projected to increase approximately $260$140 million to $270$150 million.
•Property taxes are projected to increase approximately $35 million to $45 million.
•Interest expense (net of AFUDC - debt) is projected to increase $45$110 million to $55$120 million.
•AFUDC - equity is projected to be relatively flat.increase $0 million to $10 million.
•ETR is projected to be ~(5%) to (6%(7%). The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.
(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
•Deliver long-term annual EPS growth of 5% to 7% based off of a 20212022 base of $2.96$3.15 per share, which represents the mid-point of the revised 2021original 2022 guidance range of $2.94$3.10 to $2.98$3.20 per share.
•Deliver annual dividend increases of 5% to 7%.
•Target a dividend payout ratio of 60% to 70%.
•Maintain senior secured debt credit ratings in the A range.
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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 20202021 under “Derivatives, Risk Management and Market Risk.” | | |
ITEM 4 — CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.
As of Sept. 30, 2021,2022, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.
PART II — OTHER INFORMATION
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ITEM 1 — LEGAL PROCEEDINGS |
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 10 to the consolidated financial statements and Part I Item 2 for further information.
Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2020,2021, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.
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ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
Purchases of Equity Securities by the Issuer and Affiliated PurchasersPurchaser:
For the quarter endedSept. 30, 2021, 2022, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
* Indicates incorporation by reference
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Exhibit Number | Description | Report or Registration Statement | Exhibit Reference |
| | Xcel Energy Inc. Form 8-K dated May 16, 2012 | 3.01 |
| | Xcel Energy Inc Form 8-K dated April 3, 2020 | 3.01 |
| | NSP-Wisconsin Form 8-K dated July 20, 202115, 2022 | 4.01 |
| Summary of Non-Employee Director Compensation, effectiveFourth Amended and Restated Credit Agreement, dated as of October 1, 2021September 19, 2022, among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank Ltd. and Wells Fargo Bank, National Association, as Documentation Agents | Xcel Energy Inc. Form 8-K dated September 19, 2022 | 99.01 |
| Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Northern States Power Company, a Minnesota corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association as Documentation Agents | Xcel Energy Inc. Form 8-K dated September 19, 2022 | 99.02 |
| Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Public Service Company of Colorado, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents | Xcel Energy Inc. Form 8-K dated September 19, 2022 | 99.03 |
| Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Southwestern Public Service Company, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents | Xcel Energy Inc. Form 8-K dated September 19, 2022 | 99.04 |
| Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Northern States Power Company, a Wisconsin corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents | Xcel Energy Inc. Form 8-K dated September 19, 2022 | 99.05 |
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101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | |
101.SCH | Inline XBRL Schema | | |
101.CAL | Inline XBRL Calculation | | |
101.DEF | Inline XBRL Definition | | |
101.LAB | Inline XBRL Label | | |
101.PRE | Inline XBRL Presentation | | |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | | |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | XCEL ENERGY INC. |
| | |
October 28, 202110/27/2022 | By: | /s/ JEFFREY S. SAVAGE |
| | Jeffrey S. Savage |
| | Senior Vice President, Controller |
| | (Principal Accounting Officer) |
| | |
| | /s/ BRIAN J. VAN ABEL |
| | Brian J. Van Abel |
| | Executive Vice President, Chief Financial Officer |
| | (Duly Authorized Officer and Principal Financial Officer) |