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 March 31, 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 Jurisdiction of Incorporation or Organization) | | (Commission File Number)
| | (IRSI.R.S. Employer Identification No.) |
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414 Nicollet Mall | Minneapolis | Minnesota | | | | 55401 |
(Address of Principal Executive Offices)
| | | | (Zip Code) |
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612(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) |
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 April 22, 202121, 2022 |
Common Stock, $2.50 par value | | 538,206,800544,653,284 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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| Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
This Form 10-Q is filed by Xcel Energy Inc. Additional information is available on various filings with the Securities and Exchange Commission.
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-Wisconsin | Northern States Power Company, a Wisconsin corporation |
PSCo | Public Service Company of Colorado |
SPS | Southwestern Public Service Co.Company |
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
WGIWYCO | West Gas InterstateWYCO Development, LLC |
Xcel Energy | Xcel Energy Inc. and its subsidiaries |
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Federal and State Regulatory Agencies |
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 |
FERC | Federal Energy Regulatory Commission |
IRS | Internal Revenue Service |
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 |
PSCWOAG | Public Service CommissionMinnesota Office of WisconsinAttorney General |
PUCT | Public Utility Commission of Texas |
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SEC | Securities and Exchange Commission |
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Electric, Purchased Gas and Resource Adjustment Clauses |
DSM | Demand side management |
FCA | Fuel clause adjustment |
FPPCAC | Fuel and purchased power cost adjustment clause |
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 |
ASCALJ | FASB Accounting Standards CodificationAdministrative Law Judge |
BART | Best available retrofit technology |
C&I | Commercial and Industrial |
CCR | Coal combustion residualresiduals |
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 |
CFO | Chief financial officer |
CORE | CORE Electric Cooperative |
COVID-19 | Novel coronavirus |
CPCN | Certificate of Public Convenience and Necessity |
CSPV | Crystalline Silicon Photovoltaic |
CUB | Citizens Utility Board |
DRIP | Dividend Reinvestment and Stock Purchase Program |
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 |
ISO | Independent System Operator |
LLC | Limited liability company |
MDLLP&L | Multi district litigation |
MEC | Mankato Energy CenterLubbock Power and Light |
MGP | Manufactured gas plant |
MISO | Midcontinent Independent System Operator, Inc. |
NAV | Net asset value |
NOL | Net operating loss |
NOPR | Notice of Proposed Rulemaking |
O&M | Operating and maintenance |
OATT | Open Access Transmission Tariff |
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PPA | Power purchase agreement |
PTC | Production tax credit |
ROE | Return on equity |
ROFR | Right-of-first-refusal |
RTO | Regional Transmission Organization |
SMMPA | Southern Minnesota Municipal Power Agency |
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SPP | Southwest Power Pool, Inc. |
THI | Temperature-humidity index |
TOs | Transmission owners |
VaR | Value at Risk |
VIE | Variable interest entity |
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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 those relating to 20212022 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 elsewhere in this Quarterly Report on Form 10-Q and in other filings with the SEC (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020,2021 and subsequent filings),filings 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 Code of Conduct; ability to recover costs;costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures andand/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; and regulatory changes and/or limitations related to the use of natural gas as an energy source.
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 March 31 | | | Three Months Ended March 31 | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Operating revenues | Operating revenues | | | | | Operating revenues | | | | |
Electric | Electric | $ | 2,870 | | | $ | 2,203 | | | Electric | $ | 2,633 | | | $ | 2,870 | | |
Natural gas | Natural gas | 647 | | | 583 | | | Natural gas | 1,090 | | | 647 | | |
Other | Other | 24 | | | 25 | | | Other | 28 | | | 24 | | |
Total operating revenues | Total operating revenues | 3,541 | | | 2,811 | | | Total operating revenues | 3,751 | | | 3,541 | | |
| Operating expenses | Operating expenses | | | Operating expenses | | |
Electric fuel and purchased power | Electric fuel and purchased power | 1,386 | | | 797 | | | Electric fuel and purchased power | 1,094 | | | 1,386 | | |
Cost of natural gas sold and transported | Cost of natural gas sold and transported | 299 | | | 285 | | | Cost of natural gas sold and transported | 710 | | | 299 | | |
Cost of sales — other | Cost of sales — other | 8 | | | 9 | | | Cost of sales — other | 10 | | | 8 | | |
Operating and maintenance expenses | Operating and maintenance expenses | 584 | | | 579 | | | Operating and maintenance expenses | 602 | | | 584 | | |
Conservation and demand side management expenses | Conservation and demand side management expenses | 73 | | | 74 | | | Conservation and demand side management expenses | 92 | | | 73 | | |
Depreciation and amortization | Depreciation and amortization | 521 | | | 463 | | | Depreciation and amortization | 562 | | | 521 | | |
Taxes (other than income taxes) | Taxes (other than income taxes) | 163 | | | 149 | | | Taxes (other than income taxes) | 171 | | | 163 | | |
Total operating expenses | Total operating expenses | 3,034 | | | 2,356 | | | Total operating expenses | 3,241 | | | 3,034 | | |
| Operating income | Operating income | 507 | | | 455 | | | Operating income | 510 | | | 507 | | |
| Other income (expense), net | 5 | | | (11) | | | |
Equity earnings of unconsolidated subsidiaries | 14 | | | 11 | | | |
Other income, net | | Other income, net | 1 | | | 5 | | |
Earnings from equity method investments | | Earnings from equity method investments | 15 | | | 14 | | |
Allowance for funds used during construction — equity | Allowance for funds used during construction — equity | 14 | | | 23 | | | Allowance for funds used during construction — equity | 13 | | | 14 | | |
| Interest charges and financing costs | Interest charges and financing costs | | | Interest charges and financing costs | | |
Interest charges — includes other financing costs of $7 and $7, respectively | 205 | | | 199 | | | |
Interest charges — includes other financing costs of $8 and $7, respectively | | Interest charges — includes other financing costs of $8 and $7, respectively | 214 | | | 205 | | |
Allowance for funds used during construction — debt | Allowance for funds used during construction — debt | (5) | | | (10) | | | Allowance for funds used during construction — debt | (5) | | | (5) | | |
Total interest charges and financing costs | Total interest charges and financing costs | 200 | | | 189 | | | Total interest charges and financing costs | 209 | | | 200 | | |
| Income before income taxes | Income before income taxes | 340 | | | 289 | | | Income before income taxes | 330 | | | 340 | | |
Income tax benefit | Income tax benefit | (22) | | | (6) | | | Income tax benefit | (50) | | | (22) | | |
Net income | Net income | $ | 362 | | | $ | 295 | | | Net income | $ | 380 | | | $ | 362 | | |
| Weighted average common shares outstanding: | Weighted average common shares outstanding: | | | Weighted average common shares outstanding: | | |
Basic | Basic | 538 | | | 526 | | | Basic | 545 | | | 538 | | |
Diluted | Diluted | 539 | | | 527 | | | Diluted | 545 | | | 539 | | |
| Earnings per average common share: | Earnings per average common share: | | | Earnings per average common share: | | |
Basic | Basic | $ | 0.67 | | | $ | 0.56 | | | Basic | $ | 0.70 | | | $ | 0.67 | | |
Diluted | Diluted | 0.67 | | | 0.56 | | | Diluted | 0.70 | | | 0.67 | | |
| 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 March 31 | | | Three Months Ended March 31 | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Net income | Net income | $ | 362 | | | $ | 295 | | | Net income | $ | 380 | | | $ | 362 | | |
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: | | |
| Amortization of losses included in net periodic benefit cost, net of tax of $0 and $0, respectively | 0 | | | 1 | | | |
Reclassifications of loss to net income, net of tax of $1 and $—, respectively | | Reclassifications of loss to net income, net of tax of $1 and $—, respectively | 1 | | | — | | |
Derivative instruments: | Derivative instruments: | | | Derivative instruments: | | |
Net fair value decrease, net of tax of $0 and $(3), respectively | 0 | | | (10) | | | |
Reclassification of losses to net income, net of tax of $1 and $0, respectively | 3 | | | 2 | | | |
Net fair value increase, net of tax of $1 and $—, respectively | | Net fair value increase, net of tax of $1 and $—, respectively | 5 | | | — | | |
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 | 1 | | | 3 | | |
| Total other comprehensive income (loss) | 3 | | | (7) | | | |
Total other comprehensive income | | Total other comprehensive income | 7 | | | 3 | | |
Total comprehensive income | Total comprehensive income | $ | 365 | | | $ | 288 | | | Total comprehensive income | $ | 387 | | | $ | 365 | | |
| 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)
| | | Three Months Ended March 31 | | Three Months Ended March 31 |
| | 2021 | | 2020 | | 2022 | | 2021 |
Operating activities | Operating activities | | | | Operating activities | | | |
Net income | Net income | $ | 362 | | | $ | 295 | | Net income | $ | 380 | | | $ | 362 | |
Adjustments to reconcile net income to cash (used in) provided by operating activities: | | |
Adjustments to reconcile net income to cash provided by (used in) operating activities: | | Adjustments to reconcile net income to cash provided by (used in) operating activities: | |
Depreciation and amortization | Depreciation and amortization | 517 | | | 466 | | Depreciation and amortization | 567 | | | 517 | |
Nuclear fuel amortization | Nuclear fuel amortization | 30 | | | 33 | | Nuclear fuel amortization | 30 | | | 30 | |
Deferred income taxes | Deferred income taxes | (23) | | | 34 | | Deferred income taxes | (55) | | | (23) | |
Allowance for equity funds used during construction | Allowance for equity funds used during construction | (14) | | | (23) | | Allowance for equity funds used during construction | (13) | | | (14) | |
Equity earnings of unconsolidated subsidiaries | (14) | | | (11) | | |
Dividends from unconsolidated subsidiaries | 11 | | | 11 | | |
Earnings from equity method investments | | Earnings from equity method investments | (15) | | | (14) | |
Dividends from equity method investments | | Dividends from equity method investments | 10 | | | 11 | |
Provision for bad debts | Provision for bad debts | 14 | | | 13 | | Provision for bad debts | 17 | | | 14 | |
Share-based compensation expense | Share-based compensation expense | 9 | | | 26 | | Share-based compensation expense | 4 | | | 9 | |
Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
Accounts receivable | Accounts receivable | (57) | | | (6) | | Accounts receivable | (191) | | | (57) | |
Accrued unbilled revenues | Accrued unbilled revenues | 123 | | | 149 | | Accrued unbilled revenues | 146 | | | 123 | |
Inventories | Inventories | 39 | | | 33 | | Inventories | 107 | | | 39 | |
Other current assets | Other current assets | 8 | | | (31) | | Other current assets | (10) | | | 8 | |
Accounts payable | Accounts payable | (21) | | | (201) | | Accounts payable | (34) | | | (21) | |
Net regulatory assets and liabilities | Net regulatory assets and liabilities | (961) | | | 101 | | Net regulatory assets and liabilities | 215 | | | (961) | |
Other current liabilities | Other current liabilities | 13 | | | (77) | | Other current liabilities | 51 | | | 13 | |
Pension and other employee benefit obligations | Pension and other employee benefit obligations | (132) | | | (157) | | Pension and other employee benefit obligations | (31) | | | (132) | |
Other, net | Other, net | (40) | | | 14 | | Other, net | (38) | | | (40) | |
Net cash (used in) provided by operating activities | (136) | | | 669 | | |
Net cash provided by (used in) operating activities | | Net cash provided by (used in) operating activities | 1,140 | | | (136) | |
| Investing activities | Investing activities | | Investing activities | |
Capital/construction expenditures | Capital/construction expenditures | (1,024) | | | (1,607) | | Capital/construction expenditures | (942) | | | (1,024) | |
Purchase of investment securities | Purchase of investment securities | (199) | | | (835) | | Purchase of investment securities | (156) | | | (199) | |
Proceeds from the sale of investment securities | Proceeds from the sale of investment securities | 194 | | | 830 | | Proceeds from the sale of investment securities | 147 | | | 194 | |
Other, net | Other, net | (6) | | | 6 | | Other, net | (1) | | | (6) | |
Net cash used in investing activities | Net cash used in investing activities | (1,035) | | | (1,606) | | Net cash used in investing activities | (952) | | | (1,035) | |
| Financing activities | Financing activities | | Financing activities | |
Proceeds from short-term borrowings, net | 893 | | | 1,170 | | |
Proceeds from (repayments of) short-term borrowings, net | | Proceeds from (repayments of) short-term borrowings, net | (9) | | | 893 | |
Proceeds from issuances of long-term debt | Proceeds from issuances of long-term debt | 1,821 | | | 0 | | Proceeds from issuances of long-term debt | — | | | 1,821 | |
Repayments of long-term debt, including reacquisition premiums | Repayments of long-term debt, including reacquisition premiums | (400) | | | 0 | | Repayments of long-term debt, including reacquisition premiums | — | | | (400) | |
| Dividends paid | Dividends paid | (223) | | | (204) | | Dividends paid | (240) | | | (223) | |
Other, net | Other, net | (10) | | | (33) | | Other, net | (15) | | | (10) | |
Net cash provided by financing activities | 2,081 | | | 933 | | |
Net cash (used in) provided by financing activities | | Net cash (used in) provided by financing activities | (264) | | | 2,081 | |
| Net change in cash, cash equivalents and restricted cash | Net change in cash, cash equivalents and restricted cash | 910 | | | (4) | | Net change in cash, cash equivalents and restricted cash | (76) | | | 910 | |
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 | $ | 1,039 | | | $ | 244 | | Cash, cash equivalents and restricted cash at end of period | $ | 90 | | | $ | 1,039 | |
| 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) | $ | (206) | | | $ | (207) | | Cash paid for interest (net of amounts capitalized) | $ | (202) | | | $ | (206) | |
Cash (paid) received for income taxes, net | (3) | | | 0 | | |
Cash paid for income taxes, net | | Cash paid for income taxes, net | — | | | (3) | |
| 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 | $ | 412 | | | $ | 284 | | Accrued property, plant and equipment additions | $ | 288 | | | $ | 412 | |
Inventory transfers to property, plant and equipment | Inventory transfers to property, plant and equipment | 22 | | | 33 | | Inventory transfers to property, plant and equipment | 20 | | | 22 | |
| Allowance for equity funds used during construction | Allowance for equity funds used during construction | 14 | | | 23 | | Allowance for equity funds used during construction | 13 | | | 14 | |
Issuance of common stock for equity awards | 19 | | | 18 | | |
Issuance of common stock for reinvested dividends and/or equity awards | | Issuance of common stock for reinvested dividends and/or equity awards | 11 | | | 19 | |
| 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)
| | | | | | | | | | | |
| March 31, 2021 | | Dec. 31, 2020 |
Assets | | | |
Current assets | | | |
Cash and cash equivalents | $ | 1,039 | | | $ | 129 | |
Accounts receivable, net | 959 | | | 916 | |
Accrued unbilled revenues | 591 | | | 714 | |
Inventories | 469 | | | 535 | |
Regulatory assets | 928 | | | 640 | |
Derivative instruments | 44 | | | 49 | |
Prepaid taxes | 41 | | | 42 | |
Prepayments and other | 244 | | | 250 | |
Total current assets | 4,315 | | | 3,275 | |
| | | |
Property, plant and equipment, net | 43,582 | | | 42,950 | |
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Other assets | | | |
Nuclear decommissioning fund and other investments | 3,154 | | | 3,096 | |
Regulatory assets | 3,552 | | | 2,737 | |
Derivative instruments | 59 | | | 30 | |
Operating lease right-of-use assets | 1,440 | | | 1,490 | |
Other | 409 | | | 379 | |
Total other assets | 8,614 | | | 7,732 | |
Total assets | $ | 56,511 | | | $ | 53,957 | |
| | | |
Liabilities and Equity | | | |
Current liabilities | | | |
Current portion of long-term debt | $ | 21 | | | $ | 421 | |
Short-term debt | 1,477 | | | 584 | |
Accounts payable | 1,213 | | | 1,237 | |
Regulatory liabilities | 406 | | | 311 | |
Taxes accrued | 684 | | | 578 | |
Accrued interest | 191 | | | 203 | |
Dividends payable | 246 | | | 231 | |
Derivative instruments | 48 | | | 53 | |
Operating lease liabilities | 221 | | | 214 | |
Other | 370 | | | 407 | |
Total current liabilities | 4,877 | | | 4,239 | |
| | | |
Deferred credits and other liabilities | | | |
Deferred income taxes | 4,765 | | | 4,746 | |
| | | |
Regulatory liabilities | 5,353 | | | 5,302 | |
Asset retirement obligations | 2,980 | | | 2,884 | |
Derivative instruments | 143 | | | 131 | |
Customer advances | 195 | | | 197 | |
Pension and employee benefit obligations | 516 | | | 666 | |
Operating lease liabilities | 1,287 | | | 1,344 | |
Other | 225 | | | 228 | |
Total deferred credits and other liabilities | 15,464 | | | 15,498 | |
| | | |
Commitments and contingencies | 0 | | 0 |
Capitalization | | | |
Long-term debt | 21,470 | | | 19,645 | |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 538,076,662 and 537,438,394 shares outstanding at March 31, 2021 and Dec. 31, 2020, respectively | 1,345 | | | 1,344 | |
Additional paid in capital | 7,411 | | | 7,404 | |
Retained earnings | 6,082 | | | 5,968 | |
Accumulated other comprehensive loss | (138) | | | (141) | |
Total common stockholders’ equity | 14,700 | | | 14,575 | |
Total liabilities and equity | $ | 56,511 | | | $ | 53,957 | |
| | | |
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 March 31, 2021 and 2020 | | | | | | | | | | | | |
Balance at Dec. 31, 2019 | 524,539,000 | | | $ | 1,311 | | | $ | 6,656 | | | $ | 5,413 | | | $ | (141) | | | $ | 13,239 | | |
Net income | | 295 | | | 295 | | |
Other comprehensive loss | | (7) | | | (7) | | |
Dividends declared on common stock ($0.43 per share) | | (227) | | | (227) | | |
Issuances of common stock | 494,594 | | | 2 | | | 10 | | | 12 | | |
Share-based compensation | | (7) | | | (1) | | | (8) | | |
Adoption of ASC Topic 326 | | (2) | | | (2) | | |
Balance at March 31, 2020 | 525,033,594 | | | $ | 1,313 | | | $ | 6,659 | | | $ | 5,478 | | | $ | (148) | | | $ | 13,302 | | |
| Three Months Ended March 31, 2022 and 2021 | | Three Months Ended March 31, 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 | | Balance at Dec. 31, 2020 | 537,438,394 | | | $ | 1,344 | | | $ | 7,404 | | | $ | 5,968 | | | $ | (141) | | | $ | 14,575 | |
Net income | Net income | | 362 | | | 362 | | Net income | | 362 | | | 362 | |
Other comprehensive income | Other comprehensive income | | 3 | | | 3 | | Other comprehensive income | | 3 | | | 3 | |
Dividends declared on common stock ($0.4575 per share) | Dividends declared on common stock ($0.4575 per share) | | | (246) | | | (246) | | Dividends declared on common stock ($0.4575 per share) | | (246) | | | (246) | |
Issuances of common stock | Issuances of common stock | 638,268 | | | 1 | | | 14 | | | 15 | | Issuances of common stock | 638,268 | | | 1 | | | 14 | | | 15 | |
| Share-based compensation | Share-based compensation | | (7) | | | (2) | | | (9) | | Share-based compensation | | (7) | | | (2) | | | (9) | |
Balance at March 31, 2021 | Balance at March 31, 2021 | 538,076,662 | | | $ | 1,345 | | | $ | 7,411 | | | $ | 6,082 | | | $ | (138) | | | $ | 14,700 | | Balance at March 31, 2021 | 538,076,662 | | | $ | 1,345 | | | $ | 7,411 | | | $ | 6,082 | | | $ | (138) | | | $ | 14,700 | |
| 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 | | 380 | | | 380 | |
Other comprehensive income | | Other comprehensive income | | 7 | | | 7 | |
Dividends declared on common stock ($0.4875 per share) | | Dividends declared on common stock ($0.4875 per share) | | (265) | | | (265) | |
Issuances of common stock | | Issuances of common stock | 505,718 | | | 1 | | | 11 | | | 12 | |
| Share-based compensation | | Share-based compensation | | (13) | | | (1) | | | (14) | |
Balance at March 31, 2022 | | Balance at March 31, 2022 | 544,530,987 | | | $ | 1,361 | | | $ | 7,801 | | | $ | 6,686 | | | $ | (116) | | | $ | 15,732 | |
| | | | 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)
| | | | | | | | | | | |
| March 31, 2022 | | Dec. 31, 2021 |
Assets | | | |
Current assets | | | |
Cash and cash equivalents | $ | 90 | | | $ | 166 | |
Accounts receivable, net | 1,190 | | | 1,018 | |
Accrued unbilled revenues | 716 | | | 862 | |
Inventories | 505 | | | 631 | |
Regulatory assets | 1,049 | | | 1,106 | |
Derivative instruments | 125 | | | 123 | |
Prepaid taxes | 40 | | | 44 | |
Prepayments and other | 307 | | | 289 | |
Total current assets | 4,022 | | | 4,239 | |
| | | |
Property, plant and equipment, net | 45,837 | | | 45,457 | |
| | | |
Other assets | | | |
Nuclear decommissioning fund and other investments | 3,492 | | | 3,628 | |
Regulatory assets | 2,841 | | | 2,738 | |
Derivative instruments | 94 | | | 67 | |
Operating lease right-of-use assets | 1,239 | | | 1,291 | |
Other | 460 | | | 431 | |
Total other assets | 8,126 | | | 8,155 | |
Total assets | $ | 57,985 | | | $ | 57,851 | |
| | | |
Liabilities and Equity | | | |
Current liabilities | | | |
Current portion of long-term debt | $ | 851 | | | $ | 601 | |
Short-term debt | 996 | | | 1,005 | |
Accounts payable | 1,257 | | | 1,409 | |
Regulatory liabilities | 359 | | | 271 | |
Taxes accrued | 685 | | | 569 | |
Accrued interest | 209 | | | 209 | |
Dividends payable | 265 | | | 249 | |
Derivative instruments | 97 | | | 69 | |
Operating lease liabilities | 203 | | | 205 | |
Other | 430 | | | 459 | |
Total current liabilities | 5,352 | | | 5,046 | |
| | | |
Deferred credits and other liabilities | | | |
Deferred income taxes | 4,822 | | | 4,894 | |
Deferred investment tax credits | 52 | | | 53 | |
Regulatory liabilities | 5,470 | | | 5,405 | |
Asset retirement obligations | 3,210 | | | 3,151 | |
Derivative instruments | 107 | | | 105 | |
Customer advances | 192 | | | 196 | |
Pension and employee benefit obligations | 262 | | | 306 | |
Operating lease liabilities | 1,094 | | | 1,146 | |
Other | 158 | | | 158 | |
Total deferred credits and other liabilities | 15,367 | | | 15,414 | |
| | | |
Commitments and contingencies | 0 | | 0 |
Capitalization | | | |
Long-term debt | 21,534 | | | 21,779 | |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 544,530,987 and 544,025,269 shares outstanding at March 31, 2022 and Dec. 31, 2021, respectively | 1,361 | | | 1,360 | |
Additional paid in capital | 7,801 | | | 7,803 | |
Retained earnings | 6,686 | | | 6,572 | |
Accumulated other comprehensive loss | (116) | | | (123) | |
Total common stockholders’ equity | 15,732 | | | 15,612 | |
Total liabilities and equity | $ | 57,985 | | | $ | 57,851 | |
| | | |
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 March 31, 20212022 and Dec. 31, 2020;2021; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, cash flows and changes in stockholders’ equity for the three months ended March 31, 20212022 and 2020.2021; and Xcel Energy’s cash flows for the three months ended March 31, 2022 and 2021.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 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.
| | |
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. | | |
2. Accounting Pronouncements |
Recently Adopted
Credit Losses— In 2016,As of March 31, 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.
| | |
3. Selected Balance Sheet Data |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2021 | | Dec. 31, 2020 |
Accounts receivable, net | | | | |
Accounts receivable | | $ | 1,045 | | | $ | 995 | |
Less allowance for bad debts | | (86) | | | (79) | |
Accounts receivable, net | | $ | 959 | | | $ | 916 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2021 | | Dec. 31, 2020 |
Inventories | | | | |
Materials and supplies | | $ | 279 | | | $ | 275 | |
Fuel | | 153 | | | 176 | |
Natural gas | | 37 | | | 84 | |
Total inventories | | $ | 469 | | | $ | 535 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2022 | | Dec. 31, 2021 |
Accounts receivable, net | | | | |
Accounts receivable | | $ | 1,303 | | | $ | 1,124 | |
Less allowance for bad debts | | (113) | | | (106) | |
Accounts receivable, net | | $ | 1,190 | | | $ | 1,018 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2021 | | Dec. 31, 2020 |
Property, plant and equipment, net | | | | |
Electric plant | | $ | 48,008 | | | $ | 47,104 | |
Natural gas plant | | 7,218 | | | 7,135 | |
Common and other property | | 2,527 | | | 2,503 | |
Plant to be retired (a) | | 654 | | | 677 | |
Construction work in progress | | 1,877 | | | 1,877 | |
Total property, plant and equipment | | 60,284 | | | 59,296 | |
Less accumulated depreciation | | (17,060) | | | (16,657) | |
Nuclear fuel | | 3,047 | | | 2,970 | |
Less accumulated amortization | | (2,689) | | | (2,659) | |
Property, plant and equipment, net | | $ | 43,582 | | | $ | 42,950 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2022 | | Dec. 31, 2021 |
Inventories | | | | |
Materials and supplies | | $ | 299 | | | $ | 289 | |
Fuel | | 147 | | | 182 | |
Natural gas | | 59 | | | 160 | |
Total inventories | | $ | 505 | | | $ | 631 | |
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2022 | | Dec. 31, 2021 |
Property, plant and equipment, net | | | | |
Electric plant | | $ | 49,495 | | | $ | 48,680 | |
Natural gas plant | | 7,881 | | | 7,758 | |
Common and other property | | 2,715 | | | 2,602 | |
Plant to be retired (a) | | 1,151 | | | 1,200 | |
Construction work in progress | | 1,733 | | | 1,969 | |
Total property, plant and equipment | | 62,975 | | | 62,209 | |
Less accumulated depreciation | | (17,420) | | | (17,060) | |
Nuclear fuel | | 3,085 | | | 3,081 | |
Less accumulated amortization | | (2,803) | | | (2,773) | |
Property, plant and equipment, net | | $ | 45,837 | | | $ | 45,457 | |
(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo and Sherco Units 1, 2 and 23 and A.S. King for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.
| | |
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 were as follows:Energy:
| (Amounts in Millions, Except Interest Rates) | (Amounts in Millions, Except Interest Rates) | | Three Months Ended March 31, 2021 | | Year Ended Dec. 31, 2020 | (Amounts in Millions, Except Interest Rates) | | Three Months Ended March 31, 2022 | | Year Ended Dec. 31, 2021 |
Borrowing limit | Borrowing limit | | $ | 4,300 | | | $ | 3,100 | | Borrowing limit | | $ | 3,100 | | | $ | 3,100 | |
Amount outstanding at period end | Amount outstanding at period end | | 1,477 | | | 584 | | Amount outstanding at period end | | 996 | | | 1,005 | |
Average amount outstanding | Average amount outstanding | | 1,129 | | | 1,126 | | Average amount outstanding | | 1,061 | | | 1,399 | |
Maximum amount outstanding | Maximum amount outstanding | | 2,054 | | | 2,080 | | Maximum amount outstanding | | 1,357 | | | 2,054 | |
Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.53 | % | | 1.45 | % | Weighted average interest rate, computed on a daily basis | | 0.42 | % | | 0.57 | % |
Weighted average interest rate at period end | Weighted average interest rate at period end | | 0.73 | | | 0.23 | | Weighted average interest rate at period end | | 0.93 | | | 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. At both March 31, 2021There were $39 million and Dec. 31, 2020, there were $20$19 million of letters of credit outstanding under the credit facilities.credit facilities at March 31, 2022 and Dec. 31, 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 in place at least equal to the amount of commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities.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.
As of March 31, 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 | | | $ | 277 | | | $ | 973 | | Xcel Energy Inc. | | $ | 1,250 | | | $ | 780 | | | $ | 470 | |
PSCo | PSCo | | 700 | | | 8 | | | 692 | | PSCo | | 700 | | | 31 | | | 669 | |
NSP-Minnesota | NSP-Minnesota | | 500 | | | 10 | | | 490 | | NSP-Minnesota | | 500 | | | 11 | | | 489 | |
SPS | SPS | | 500 | | | 2 | | | 498 | | SPS | | 500 | | | 214 | | | 286 | |
NSP-Wisconsin | NSP-Wisconsin | | 150 | | | 0 | | | 150 | | NSP-Wisconsin | | 150 | | | — | | | 150 | |
Total | Total | | $ | 3,100 | | | $ | 297 | | | $ | 2,803 | | Total | | $ | 3,100 | | | $ | 1,036 | | | $ | 2,064 | |
(a)Expires in June 2024.
(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 revolving credit facility termination date for two additional one-year periods. 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.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities.facilities capacity. Xcel Energy Inc. and its utility subsidiaries had 0no direct advances on the credit facilities outstanding as of March 31, 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 percent.
As of March 31, 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 | | | $ | 0 | |
2021.Bilateral Credit Agreement
In April 2021, the2022, 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 March 31, 2021,2022, NSP-Minnesota’s outstanding letters of credit under the bilateral credit agreement were as follows:
| | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
NSP-Minnesota | | $ | 75 | | | $ | 49 | | | $ | 26 | |
Long-Term Borrowings and Other Financing Instruments
During the three months ended March 31, 2021, Xcel Energy Inc. and its utility subsidiaries issued the following:
•PSCoissued $750 million of 1.875% first mortgage bonds due June 15, 2031.
•SPS issued $250 million of 3.15% first mortgage bonds due 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 April 1, 2052. | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
NSP-Minnesota | | $ | 75 | | | $ | 45 | | | $ | 30 | |
Other Equity — Xcel Energy Inc. issued $13$10 million and $10$13 million of equity through the DRIP during the three months ended March 31, 20212022 and 2020,2021, respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock through a non-cash transaction.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 March 31, 2021 | | Three Months Ended March 31, 2022 |
(Millions of Dollars) | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | Major revenue types | | | | | | | | | Major revenue types | | | | | | | | |
Revenue from contracts with customers: | Revenue from contracts with customers: | Revenue from contracts with customers: |
Residential | Residential | | $ | 733 | | | $ | 384 | | | $ | 10 | | | $ | 1,127 | | Residential | | $ | 817 | | | $ | 663 | | | $ | 9 | | | $ | 1,489 | |
C&I | C&I | | 1,033 | | | 187 | | | 9 | | | 1,229 | | C&I | | 1,235 | | | 356 | | | 2 | | | 1,593 | |
Other | Other | | 30 | | | 0 | | | 2 | | | 32 | | Other | | 32 | | | — | | | 14 | | | 46 | |
Total retail | Total retail | | 1,796 | | | 571 | | | 21 | | | 2,388 | | Total retail | | 2,084 | | | 1,019 | | | 25 | | | 3,128 | |
Wholesale | Wholesale | | 743 | | | 0 | | | 0 | | | 743 | | Wholesale | | 259 | | | — | | | — | | | 259 | |
Transmission | Transmission | | 146 | | | 0 | | | 0 | | | 146 | | Transmission | | 152 | | | — | | | — | | | 152 | |
Other | Other | | 13 | | | 19 | | | 0 | | | 32 | | Other | | 23 | | | 45 | | | — | | | 68 | |
Total revenue from contracts with customers | Total revenue from contracts with customers | | 2,698 | | | 590 | | | 21 | | | 3,309 | | Total revenue from contracts with customers | | 2,518 | | | 1,064 | | | 25 | | | 3,607 | |
Alternative revenue and other | Alternative revenue and other | | 172 | | | 57 | | | 3 | | | 232 | | Alternative revenue and other | | 115 | | | 26 | | | 3 | | | 144 | |
Total revenues | Total revenues | | $ | 2,870 | | | $ | 647 | | | $ | 24 | | | $ | 3,541 | | Total revenues | | $ | 2,633 | | | $ | 1,090 | | | $ | 28 | | | $ | 3,751 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2020 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 676 | | | $ | 355 | | | $ | 11 | | | $ | 1,042 | |
C&I | | 1,066 | | | 180 | | | 9 | | | 1,255 | |
Other | | 29 | | | 0 | | | 1 | | | 30 | |
Total retail | | 1,771 | | | 535 | | | 21 | | | 2,327 | |
Wholesale | | 166 | | | 0 | | | 0 | | | 166 | |
Transmission | | 132 | | | 0 | | | 0 | | | 132 | |
Other | | 17 | | | 32 | | | 0 | | | 49 | |
Total revenue from contracts with customers | | 2,086 | | | 567 | | | 21 | | | 2,674 | |
Alternative revenue and other | | 117 | | | 16 | | | 4 | | | 137 | |
Total revenues | | $ | 2,203 | | | $ | 583 | | | $ | 25 | | | $ | 2,811 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2021 |
(Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
Major revenue types | | | | | | | | |
Revenue from contracts with customers: |
Residential | | $ | 733 | | | $ | 384 | | | $ | 10 | | | $ | 1,127 | |
C&I | | 1,033 | | | 187 | | | 9 | | | 1,229 | |
Other | | 30 | | | — | | | 2 | | | 32 | |
Total retail | | 1,796 | | | 571 | | | 21 | | | 2,388 | |
Wholesale | | 743 | | | — | | | — | | | 743 | |
Transmission | | 146 | | | — | | | — | | | 146 | |
Other | | 13 | | | 19 | | | — | | | 32 | |
Total revenue from contracts with customers | | 2,698 | | | 590 | | | 21 | | | 3,309 | |
Alternative revenue and other | | 172 | | | 57 | | | 3 | | | 232 | |
Total revenues | | $ | 2,870 | | | $ | 647 | | | $ | 24 | | | $ | 3,541 | |
Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 20202021 represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated herein by reference. The following table reconciles the differenceDifference between the statutory rate and the ETR:
| | | Three Months Ended March 31 | | | Three Months Ended March 31 | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Federal statutory rate | Federal statutory rate | | 21.0 | % | | 21.0 | % | | Federal statutory rate | | 21.0 | % | | 21.0 | % | |
State tax (net of federal tax effect) | State tax (net of federal tax effect) | | 4.9 | | | 4.9 | | | State tax (net of federal tax effect) | | 4.9 | | | 4.9 | | |
Decreases: | Decreases: | | | Decreases: | | |
Wind PTCs | Wind PTCs | | (24.6) | | | (17.2) | | | Wind PTCs | | (34.4) | | | (24.6) | | |
Plant regulatory differences (a) | Plant regulatory differences (a) | | (6.1) | | | (8.4) | | | Plant regulatory differences (a) | | (4.8) | | | (6.1) | | |
Other tax credits, net operating loss & tax credits allowances | | Other tax credits, net operating loss & tax credits allowances | | (1.5) | | | (1.1) | | |
Other (net) | Other (net) | | (1.7) | | | (2.4) | | | Other (net) | | (0.4) | | | (0.6) | | |
Effective income tax rate | Effective income tax rate | | (6.5) | % | | (2.1) | % | | Effective income tax rate | | (15.2) | % | | (6.5) | % | |
(a)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 credits 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
| | January 2022 |
2017 | | September 2021 |
Additionally, the statute of limitations related to the 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 March 31, 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 | | 2009 |
Minnesota | | 2013 |
Texas | | 2012 |
Wisconsin | | 2016 |
•In July 2020, Minnesota began a review of tax years 2015 - 2018. In February 2021, Minnesota concluded its review and commenced an audit of the same tax years. As of March 31, 2021, 0 material adjustments have been proposed.
•In January 2021, Wisconsin concluded its’ audit of tax years 2014 - 2016 with 0 material adjustments.
•In March 2021, Wisconsin began an audit of tax years 2016 - 2019. As of March 31, 2021, 0 material adjustments have been proposed.
•NaN other state income tax audits were in progress as of March 31, 2021.
Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.
Unrecognized tax benefits — permanent vs. temporary:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2021 | | Dec. 31, 2020 |
Unrecognized tax benefit — Permanent tax positions | | $ | 42 | | | $ | 41 | |
Unrecognized tax benefit — Temporary tax positions | | 11 | | | 11 | |
Total unrecognized tax benefit | | $ | 53 | | | $ | 52 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
| | | | | | | | | | | | | | |
(Millions of Dollars) | | March 31, 2021 | | Dec. 31, 2020 |
NOL and tax credit carryforwards | | $ | (32) | | | $ | (31) | |
As IRS 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) | | March 31, 2021 | | Dec. 31, 2020 |
Payable for interest related to unrecognized tax benefits at beginning of period | | $ | (3) | | | $ | 0 | |
Interest expense related to unrecognized tax benefits | | 0 | | | (3) | |
Payable for interest related to unrecognized tax benefits at end of period | | $ | (3) | | | $ | (3) | |
NaN amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2021 or Dec. 31, 2020.
Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted average 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 for settlement 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 March 31 | | Three Months Ended March 31 | |
(Shares in Millions) | (Shares in Millions) | | 2021 | | 2020 | (Shares in Millions) | | 2022 | | 2021 | |
Basic | Basic | | 538 | | | 526 | Basic | | 545 | | | 538 | |
Diluted (a) | Diluted (a) | | 539 | | 527 | | Diluted (a) | | 545 | | 539 | | |
(a)Diluted common shares outstanding included common stock equivalents of 0.2 million and 0.8 million for the three months ended March 31, 20212022 and 2020,2021, respectively.
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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 fundsfunds’ 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 forecasts of forward prices and volatilitiesinputs 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 a 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 value of an FTR is derived from, and designed to offset, the cost 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.
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. Given the limited observability 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 included inexpected to be recovered through fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction and therefore changes in the fair value of the yet to be settled portions of most FTRs are 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 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$1.2 billion and $981$1.3 billion as of March 31, 2022 and Dec. 31, 2021, respectively, and unrealized losses were $37 million and $7 million as of March 31, 20212022 and Dec. 31, 2020, respectively, and unrealized losses were $8 million and $5 million as of March 31, 2021, and Dec. 31, 2020, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
| | | March 31, 2021 | | March 31, 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 | | $ | 32 | | | $ | 32 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 32 | | Cash equivalents | | $ | 80 | | | $ | 80 | | | $ | — | | | $ | — | | | $ | — | | | $ | 80 | |
Commingled funds | Commingled funds | | 795 | | | 0 | | | 0 | | | 0 | | | 1,052 | | | 1,052 | | Commingled funds | | 871 | | | — | | | — | | | — | | | 1,258 | | | 1,258 | |
Debt securities | Debt securities | | 562 | | | 0 | | | 573 | | | 13 | | | 0 | | | 586 | | Debt securities | | 626 | | | — | | | 606 | | | 10 | | | — | | | 616 | |
Equity securities | Equity securities | | 444 | | | 1,153 | | | 2 | | | 0 | | | 0 | | | 1,155 | | Equity securities | | 409 | | | 1,159 | | | 1 | | | — | | | — | | | 1,160 | |
Total | Total | | $ | 1,833 | | | $ | 1,185 | | | $ | 575 | | | $ | 13 | | | $ | 1,052 | | | $ | 2,825 | | Total | | $ | 1,986 | | | $ | 1,239 | | | $ | 607 | | | $ | 10 | | | $ | 1,258 | | | $ | 3,114 | |
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $170$215 million of equity method investments in unconsolidated subsidiaries and $159$163 million of rabbi trust assets and miscellaneous investments.
| | | Dec. 31, 2020 | | Dec. 31, 2021 |
| | | 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 | | $ | 40 | | | $ | 40 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 40 | | Cash equivalents | | $ | 64 | | | $ | 64 | | | $ | — | | | $ | — | | | $ | — | | | $ | 64 | |
Commingled funds | Commingled funds | | 787 | | | 0 | | | 0 | | | 0 | | | 1,041 | | | 1,041 | | Commingled funds | | 856 | | | — | | | — | | | — | | | 1,294 | | | 1,294 | |
Debt securities | Debt securities | | 528 | | | 0 | | | 572 | | | 13 | | | 0 | | | 585 | | Debt securities | | 631 | | | — | | | 666 | | | 9 | | | — | | | 675 | |
Equity securities | Equity securities | | 446 | | | 1,109 | | | 2 | | | 0 | | | 0 | | | 1,111 | | Equity securities | | 411 | | | 1,222 | | | 1 | | | — | | | — | | | 1,223 | |
Total | Total | | $ | 1,801 | | | $ | 1,149 | | | $ | 574 | | | $ | 13 | | | $ | 1,041 | | | $ | 2,777 | | 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 in unconsolidated subsidiaries and $154$164 million of rabbi trust assets and other miscellaneous investments.
For the three months ended March.March 31, 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 March 31, 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 | | $ | 3 | | | $ | 133 | | | $ | 202 | | | $ | 248 | | | $ | 586 | | Debt securities | | $ | 2 | | | $ | 142 | | | $ | 193 | | | $ | 279 | | | $ | 616 | |
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:
| | | March 31, 2021 | | March 31, 2022 |
| | | 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 | | $ | 23 | | | $ | 23 | | | $ | 0 | | | $ | 0 | | | $ | 23 | | Cash equivalents | | $ | 20 | | | $ | 20 | | | $ | — | | | $ | — | | | $ | 20 | |
Mutual funds | Mutual funds | | 71 | | | 81 | | | 0 | | | 0 | | | 81 | | Mutual funds | | 75 | | | 85 | | | — | | | — | | | 85 | |
Total | Total | | $ | 94 | | | $ | 104 | | | $ | 0 | | | $ | 0 | | | $ | 104 | | Total | | $ | 95 | | | $ | 105 | | | $ | — | | | $ | — | | | $ | 105 | |
| | | 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 | | | $ | 0 | | | $ | 0 | | | $ | 32 | | Cash equivalents | | $ | 20 | | | $ | 20 | | | $ | — | | | $ | — | | | $ | 20 | |
Mutual funds | Mutual funds | | 60 | | | 70 | | | 0 | | | 0 | | | 70 | | Mutual funds | | 75 | | | 89 | | | — | | | — | | | 89 | |
Total | Total | | $ | 92 | | | $ | 102 | | | $ | 0 | | | $ | 0 | | | $ | 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 March 31, 2021,2022, accumulated other comprehensive loss related to settled interest rate derivatives included $6$5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of March 31, 2021.2022, Xcel Energy had 0 unsettled interest swaps outstanding with a notional amount of $245 million. These interest rate derivatives.derivatives were designated as cash flow hedges, and as such, changes in fair value are recorded to other comprehensive income.
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 March 31, 2021,2022, Xcel Energy had 0no commodity contracts designated as cash flow hedges.
Xcel Energy 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) | | March 31, 2021 | | Dec. 31, 2020 | (Amounts in Millions) (a)(b) | | March 31, 2022 | | Dec. 31, 2021 |
Megawatt hours of electricity | Megawatt hours of electricity | | 78 | | | 87 | | Megawatt hours of electricity | | 63 | | | 80 | |
Million British thermal units of natural gas | Million British thermal units of natural gas | | 164 | | | 175 | | Million British thermal units of natural gas | | 141 | | | 156 | |
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(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 March 31, 2021, 52022, 4 of Xcel Energy’s 10 most significant counterparties for these activities, comprising $117$80 million, or 43%31%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $43$56 million, or 16%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. NaN of these significant counterparties, comprising $39$59 million or 14%23% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Impact of derivative activity:Derivative Activity —
| | | | | | | | | | | | | | |
| | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
(Millions of Dollars) | | Accumulated Other Comprehensive Loss | | Regulatory (Assets) and Liabilities |
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Three Months Ended March 31, 2021 | | | | |
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Other derivative instruments | | | | |
Electric commodity | | $ | 0 | | | $ | 2 | |
Natural gas commodity | | 0 | | | 1 | |
Total | | $ | 0 | | | $ | 3 | |
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Three Months Ended March 31, 2020 | | | | |
Derivatives designated as cash flow hedges | | | | |
Interest rate | | $ | (13) | | | $ | 0 | |
Total | | $ | (13) | | | $ | 0 | |
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| | 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 March 31, 2022 | | | | |
Derivatives designated as cash flow hedges: | | |
Interest rate | | $ | 6 | | | $ | — | |
Total | | $ | 6 | | | $ | — | |
Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | 1 | |
Natural gas commodity | | — | | | 4 | |
Total | | $ | — | | | $ | 5 | |
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Three Months Ended March 31, 2021 | | | | |
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Other derivative instruments: | | | | |
Electric commodity | | $ | — | | | $ | 2 | |
Natural gas commodity | | — | | | 1 | |
Total | | $ | — | | | $ | 3 | |
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| | | 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 March 31, 2021 | | | | | | |
Derivatives designated as cash flow hedges | | |
Three Months Ended March 31, 2022 | | Three Months Ended March 31, 2022 | | | | | |
Derivatives designated as cash flow hedges: | | Derivatives designated as cash flow hedges: | |
Interest rate | Interest rate | | $ | 2 | | (a) | $ | 0 | | | $ | 0 | | | Interest rate | | $ | 2 | | (a) | $ | — | | | $ | — | | |
Total | Total | | $ | 2 | | | $ | 0 | | | $ | 0 | | | Total | | $ | 2 | | | $ | — | | | $ | — | | |
Other derivative instruments | | | | | | | | |
Other derivative instruments: | | Other derivative instruments: | | | | | |
Commodity trading | Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 32 | | (b) | Commodity trading | | $ | — | | | $ | — | | | $ | 2 | | (b) |
Electric commodity | Electric commodity | | 0 | | | 3 | | (c) | 0 | | | Electric commodity | | — | | | (13) | | (c) | — | | |
Natural gas commodity | Natural gas commodity | | 0 | | | 8 | | (d) | (10) | | (d) | Natural gas commodity | | — | | | 3 | | (d) | (17) | | (d)(e) |
Total | Total | | $ | 0 | | | $ | 11 | | | $ | 22 | | | Total | | $ | — | | | $ | (10) | | | $ | (15) | | |
| | | | | Three Months Ended March 31, 2021 | | Three Months Ended March 31, 2021 | |
Derivatives designated as cash flow hedges: | | Derivatives designated as cash flow hedges: | |
Interest rate | | Interest rate | | $ | 2 | | (a) | $ | — | | | $ | — | | |
Total | | Total | | $ | 2 | | | $ | — | | | $ | — | | |
Other derivative instruments: | | Other derivative instruments: | | | | | |
Commodity trading | | Commodity trading | | $ | — | | | $ | — | | | $ | 32 | | (b) |
Electric commodity | | Electric commodity | | — | | | 3 | | (c) | — | | |
Natural gas commodity | | Natural gas commodity | | — | | | 8 | | (d) | (10) | | (d)(e) |
Total | | Total | | $ | — | | | $ | 11 | | | $ | 22 | | |
| | | Three Months Ended March 31, 2020 | | |
Derivatives designated as cash flow hedges | | |
Interest rate | | $ | 2 | | (a) | $ | 0 | | | $ | 0 | | | |
Total | | $ | 2 | | | $ | 0 | | | $ | 0 | | | |
Other derivative instruments | | | | | | | | |
Commodity trading | | $ | 0 | | | $ | 0 | | | $ | 1 | | (b) | |
Electric commodity | | 0 | | | (4) | | (c) | 0 | | | |
Natural gas commodity | | 0 | | | 5 | | (d) | (6) | | (d) | |
Total | | $ | 0 | | | $ | 1 | | | $ | (5) | | | |
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(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.
(d)Amounts for both the three months ended March 31, 2021 and 2020 included 0 settlement gains orSettlement 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 months ended March 31, 2021 and 2020 relaterelated to natural gas operations and wereare recorded 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 0no derivative instruments designated as fair value hedges during the three months ended March 31, 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. As of bothAt March 31, 20212022 and Dec. 31, 2020,2021, there were $4 million and $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 the other financing arrangements related to payment terms or other covenants. As of March 31, 20212022 and Dec. 31, 2020,2021, there were approximately $59$94 million and $60$64 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. ProvisionsThese 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 0no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 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:
| | | March 31, 2021 | | Dec. 31, 2020 | | March 31, 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: | | Derivatives designated as cash flow hedges: | |
Interest rate | | Interest rate | | $ | — | | | $ | 6 | | | $ | — | | | $ | 6 | | | $ | — | | | $ | 6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 4 | | | $ | 122 | | | $ | 1 | | | $ | 127 | | | $ | (102) | | | $ | 25 | | | $ | 2 | | | $ | 67 | | | $ | 1 | | | $ | 70 | | | $ | (52) | | | $ | 18 | | Commodity trading | | $ | 56 | | | $ | 188 | | | $ | 64 | | | $ | 308 | | | $ | (231) | | | $ | 77 | | | $ | 22 | | | $ | 137 | | | $ | 21 | | | $ | 180 | | | $ | (134) | | | $ | 46 | |
Electric commodity | Electric commodity | | 0 | | | 0 | | | 16 | | | 16 | | | 0 | | | 16 | | | 0 | | | 0 | | | 20 | | | 20 | | | (1) | | | 19 | | Electric commodity | | — | | | — | | | 38 | | | 38 | | | (1) | | | 37 | | | — | | | — | | | 57 | | | 57 | | | (1) | | | 56 | |
Natural gas commodity | Natural gas commodity | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 9 | | | 0 | | | 9 | | | 0 | | | 9 | | Natural gas commodity | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 18 | | | — | | | 18 | | | — | | | 18 | |
Total current derivative assets | Total current derivative assets | | $ | 4 | | | $ | 122 | | | $ | 17 | | | $ | 143 | | | $ | (102) | | | 41 | | | $ | 2 | | | $ | 76 | | | $ | 21 | | | $ | 99 | | | $ | (53) | | | 46 | | Total current derivative assets | | $ | 56 | | | $ | 194 | | | $ | 102 | | | $ | 352 | | | $ | (232) | | | 120 | | | $ | 22 | | | $ | 155 | | | $ | 78 | | | $ | 255 | | | $ | (135) | | | 120 | |
PPAs (b) | PPAs (b) | | | | | | | | | | | | 3 | | | | | | | | | | | | | 3 | | PPAs (b) | | | | | | | | | | | | 5 | | | | | | | | | | | | | 3 | |
Current derivative instruments | Current derivative instruments | | $ | 44 | | | $ | 49 | | Current derivative instruments | | $ | 125 | | | $ | 123 | |
Noncurrent derivative assets | Noncurrent derivative assets | | | | | Noncurrent derivative assets | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 6 | | | $ | 78 | | | $ | 42 | | | $ | 126 | | | $ | (77) | | | $ | 49 | | | $ | 8 | | | $ | 66 | | | $ | 8 | | | $ | 82 | | | $ | (62) | | | $ | 20 | | Commodity trading | | $ | 36 | | | $ | 66 | | | $ | 117 | | | $ | 219 | | | $ | (135) | | | $ | 84 | | | $ | 16 | | | $ | 63 | | | $ | 89 | | | $ | 168 | | | $ | (107) | | | $ | 61 | |
Electric Commodity | | 0 | | | 0 | | | 2 | | | 2 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | |
Electric commodity | | Electric commodity | | — | | | — | | | 5 | | | 5 | | | — | | | 5 | | | — | | | — | | | — | | | — | | | — | | | — | |
Total noncurrent derivative assets | Total noncurrent derivative assets | | $ | 6 | | | $ | 78 | | | $ | 44 | | | $ | 128 | | | $ | (77) | | | 51 | | | $ | 8 | | | $ | 66 | | | $ | 8 | | | $ | 82 | | | $ | (62) | | | 20 | | Total noncurrent derivative assets | | $ | 36 | | | $ | 66 | | | $ | 122 | | | $ | 224 | | | $ | (135) | | | 89 | | | $ | 16 | | | $ | 63 | | | $ | 89 | | | $ | 168 | | | $ | (107) | | | 61 | |
PPAs (b) | PPAs (b) | | | | | | | | | | | | 8 | | | | | | | | | | | | | 10 | | PPAs (b) | | | | | | | | | | | | 5 | | | | | | | | | | | | | 6 | |
Noncurrent derivative instruments | Noncurrent derivative instruments | | $ | 59 | | | $ | 30 | | Noncurrent derivative instruments | | $ | 94 | | | $ | 67 | |
| | | March 31, 2021 | | Dec. 31, 2020 | | March 31, 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 | | $ | 6 | | | $ | 132 | | | $ | 6 | | | $ | 144 | | | $ | (113) | | | $ | 31 | | | $ | 4 | | | $ | 64 | | | $ | 17 | | | $ | 85 | | | $ | (58) | | | $ | 27 | | Commodity trading | | $ | 47 | | | $ | 213 | | | $ | 50 | | | $ | 310 | | | $ | (230) | | | $ | 80 | | | $ | 19 | | | $ | 148 | | | $ | 20 | | | $ | 187 | | | $ | (143) | | | $ | 44 | |
Electric commodity | Electric commodity | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1 | | | 1 | | | (1) | | | 0 | | Electric commodity | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | |
Natural gas commodity | Natural gas commodity | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 9 | | | 0 | | | 9 | | | 0 | | | 9 | | Natural gas commodity | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 8 | | | — | | | 8 | | | — | | | 8 | |
Total current derivative liabilities | Total current derivative liabilities | | $ | 6 | | | $ | 132 | | | $ | 6 | | | $ | 144 | | | $ | (113) | | | 31 | | | $ | 4 | | | $ | 73 | | | $ | 18 | | | $ | 95 | | | $ | (59) | | | 36 | | Total current derivative liabilities | | $ | 47 | | | $ | 213 | | | $ | 51 | | | $ | 311 | | | $ | (231) | | | 80 | | | $ | 19 | | | $ | 156 | | | $ | 21 | | | $ | 196 | | | $ | (144) | | | 52 | |
PPAs (b) | PPAs (b) | | | | | | | | | | | | 17 | | | | | | | | | | | | | 17 | | PPAs (b) | | | | | | | | | | | | 17 | | | | | | | | | | | | | 17 | |
Current derivative instruments | Current derivative instruments | | $ | 48 | | | $ | 53 | | Current derivative instruments | | $ | 97 | | | $ | 69 | |
Noncurrent derivative liabilities | Noncurrent derivative liabilities | | | | | Noncurrent derivative liabilities | | | | |
Other derivative instruments: | Other derivative instruments: | | Other derivative instruments: | |
Commodity trading | Commodity trading | | $ | 2 | | | $ | 90 | | | $ | 68 | | | $ | 160 | | | $ | (70) | | | $ | 90 | | | $ | 3 | | | $ | 58 | | | $ | 60 | | | $ | 121 | | | $ | (47) | | | $ | 74 | | Commodity trading | | $ | 40 | | | $ | 64 | | | $ | 133 | | | $ | 237 | | | $ | (168) | | | $ | 69 | | | $ | 18 | | | $ | 48 | | | $ | 127 | | | $ | 193 | | | $ | (128) | | | $ | 65 | |
Total noncurrent derivative liabilities | Total noncurrent derivative liabilities | | $ | 2 | | | $ | 90 | | | $ | 68 | | | $ | 160 | | | $ | (70) | | | 90 | | | $ | 3 | | | $ | 58 | | | $ | 60 | | | $ | 121 | | | $ | (47) | | | 74 | | Total noncurrent derivative liabilities | | $ | 40 | | | $ | 64 | | | $ | 133 | | | $ | 237 | | | $ | (168) | | | 69 | | | $ | 18 | | | $ | 48 | | | $ | 127 | | | $ | 193 | | | $ | (128) | | | 65 | |
PPAs (b) | PPAs (b) | | | | | | | | | | | | 53 | | | | | | | | | | | | | 57 | | PPAs (b) | | | | | | | | | | | | 38 | | | | | | | | | | | | | 40 | |
Noncurrent derivative instruments | Noncurrent derivative instruments | | $ | 143 | | | $ | 131 | | Noncurrent derivative instruments | | $ | 107 | | | $ | 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 at March 31, 20212022 and Dec. 31, 2020.2021. At both March 31, 20212022 and Dec. 31, 2020,2021, derivative assets and liabilities include $15 million ofno obligations to return cash collateral. At March 31, 20212022 and Dec. 31, 2020,2021, derivative assets and liabilities include rights to reclaim cash collateral of $18$34 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)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 March 31 | | Three Months Ended March 31 |
(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 | Purchases | | 0 | | | 12 | | Purchases | | 5 | | | — | |
Settlements | Settlements | | (16) | | | (18) | | Settlements | | (50) | | | (16) | |
Net transactions recorded during the period: | Net transactions recorded during the period: | | Net transactions recorded during the period: | |
Gains recognized in earnings (a) | Gains recognized in earnings (a) | | 38 | | | 6 | | Gains recognized in earnings (a) | | 42 | | | 38 | |
Net gains recognized as regulatory assets and liabilities | | 14 | | | 1 | | |
Net (losses) gains recognized as regulatory assets and liabilities | | Net (losses) gains recognized as regulatory assets and liabilities | | 24 | | | 14 | |
Balance at March 31 | Balance at March 31 | | $ | (13) | | | $ | 5 | | Balance at March 31 | | $ | 40 | | | $ | (13) | |
| | |
(a)Level 3 net gains recognized in earnings are subject to offsetting net losses of derivativesderivative instruments categorized as levels 1 and 2 in the income statement.
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were 0no transfers of amounts between levels for derivative instruments for the three months ended March 31, 20212022 and 2020.2021.
Fair Value of Long-Term Debt
Other financial instruments for which the carrying amount did not equal fair value:
| | | March 31, 2021 | | Dec. 31, 2020 | | March 31, 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 | | $ | 21,491 | | | $ | 23,654 | | | $ | 20,066 | | | $ | 24,412 | | Long-term debt, including current portion | | $ | 22,385 | | | $ | 22,807 | | | $ | 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 March 31, 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 March 31 | | Three Months Ended March 31 |
| | 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 | | | $ | 0 | | | $ | 0 | | Service cost | | $ | 24 | | | $ | 26 | | | $ | — | | | $ | — | |
Interest cost (a) | Interest cost (a) | | 26 | | | 31 | | | 4 | | | 5 | | Interest cost (a) | | 27 | | | 26 | | | 4 | | | 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) | | 0 | | | (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) | | (1) | | | — | | | — | | | — | |
Net periodic benefit cost (credit) | Net periodic benefit cost (credit) | | 27 | | | 27 | | | (1) | | | (1) | | Net periodic benefit cost (credit) | | 17 | | | 27 | | | (1) | | | (1) | |
Effects of regulation | Effects of regulation | | (1) | | | 2 | | | 1 | | | 1 | | Effects of regulation | | 5 | | | (1) | | | 1 | | | 1 | |
Net benefit cost recognized for financial reporting | | $ | 26 | | | $ | 29 | | | $ | 0 | | | $ | 0 | | |
Net benefit cost (credit) recognized for financial reporting | | Net benefit cost (credit) recognized for financial reporting | | $ | 22 | | | $ | 26 | | | $ | — | | | $ | — | |
(a) The components of net periodic cost other than the service cost component are included in the line item “Other income, (expense), net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
(b) In the first quarter of 2022, Xcel Energy recognized $1 million in settlement charge true-ups related to the fourth quarter 2021.
In January 2021,2022, contributions of $125$50 million were made across 4 of Xcel Energy’s pension plans.plans. Xcel Energy does not expect additional pension contributions during 2021.
2022.
| | |
10. Commitments and Contingencies |
The following includeincludes 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, 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. Unless otherwise required by GAAP, legalLegal 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.
NaN cases remaincase remains active which include an MDLincludes a multi-district litigation matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. Settlement of approximately $3 million was reached in February 2021. The parties have sought and are awaiting court approval of the settlement.
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. 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 seeking an unspecified amount of damages. CORE alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo filed a motion to dismiss several of CORE’s claims. 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.
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.
Minnesota Winter Storm Uri Costs — In Minnesota, NSP-Minnesota is participating in a contested case regarding the prudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses.
NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders.
NSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event.
In March 2022, following February 2022 ALJ hearings, the Company and intervenors subsequently submitted initial and reply briefs to the ALJ. The OAG modified its position, recommending disallowances of up to $148 million, the largest recommendation among the intervenor positions. An ALJ decision is expected in late May and an MPUC decision is expected in Q3 of 2022.
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 accordance with a prior MPUC order, NSP-Minnesota made a compliance filing in August 2020 detailing all costs that resulted from the outage and all insurance recoveries received by NSP-Minnesota in connection with the outage.
In January 2021, the Minnesota Office of the Attorney GeneralOAG and DOC filed comments recommendingrecommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. On Jan. 27, 2021,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. A final decision by the MPUC is pending. A loss related to this matter is deemed remote.
Westmoreland Arbitration — In November 2014, insurers forof 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.Westmoreland’s insurers have recently clarified that they will seek to recover $19 million in damages, plus prejudgment interest. 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. Westmoreland’s insurers quantified their losses as approximately $36 million.
Arbitration was delayed pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. In July 2020, following the conclusion of the appeal that fully resolved the GE litigation, Westmoreland’s insurers served notice, which triggered the arbitration to resume.
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. It is uncertain when aParties participated in mediation in the second quarter of 2022. A final resolution will occur, but it is unlikely an arbitration hearing will take place before the fourth quarter 2021.has been scheduled for October 2022. 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 request for rehearing regarding the newhas subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds.
In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569methodology/calculations 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 change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. timing. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in ROEcustomers for the firstapplicable 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.periods.
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 with initial briefs filedCircuit. Oral arguments were held in March 2021.
FERC NOPR on ROE Incentive Adders — In Aprillate 2021 the FERC issuedand 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, following a comment perioddecision is expected to be complete by the end of 2021 or 2022, NSP-Minnesota, NSP-Wisconsin and SPS would prospectively discontinue charging their current 0.5% ROE incentive adders. Amounts related to a discontinuancethe third quarter of the adder would ultimately be offset by an increase in retail rates.2022.
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. SPS has intervened in bothIn August 2021, the D.C. Circuit issued a decision denying these appeals in support ofand upholding the FERC. Any refundsFERC’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. ThisIn February 2022, FERC issued an order rejecting SPS’ request for hearing. SPS has appealed that order. That appeal is stayed pending the outcome of the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.has been combined with SPS’ prior appeal.
Contract Termination — SPS and Lubbock Power & Light are parties toLP&L have a 25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions withMay 2021, SPS concerning the interpretation of contractual terms related to early termination and default. If the parties are unable to reach resolution,LP&L finalized a settlement which would terminate the contract callsupon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million, 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 agreement is subject to approval by the matter to proceed to arbitration. The amount of any damages depends on multiple factorsPUCT and is currently unknown.FERC.
Environmental
MGP, Landfill and Disposal Sites
Xcel Energy is currently investigating, remediating or performing post-closure actions at 1314 MGP, landfill or other disposal sites across its service territories.
Xcel Energy has recognized its best estimate of costs/liabilities that will result 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 CCR landfills and surface impoundments. Currently, Xcel Energy has 98 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, 0no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increases above background concentrations were detected at 4 locations. Subsequently, assessment monitoring samples were collected at these locations and, basedBased on the results,further assessments, PSCo is evaluating options for corrective action at 2 locations, 1 of which indicates potential offsite impacts to groundwater. Until PSCo completes its assessments, itThe total cost is uncertain, what impact, if any, there willbut could be onup to $35 million. PSCo is continuing to assess the operations, financial condition or cash flows.and regulatory impacts.
In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date ofby April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required Xcel Energy to expedite closure plans for 2 impoundments.
In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined impoundment at a cost of $9 million.impoundment. 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 has been working to buildalso built an alternative collection and treatment system to meet the April 11, 2021 federal CCR Rule deadline for removing the Comanche Stationremove a bottom ash pond from service. The total cost of the alternate treatment system is approximately $14$25 million. PSCo removed the pond from service in June 2021 and did not meet the deadline and has commenced discussionsApril 2021 deadline.
PSCo is in the process of negotiating a compliance order with the EPA to determine appropriate steps forward. Onceaddressing the alternative bottom ash systemclosure deadline as well as other issues. PSCo is operational,proceeding with the existing impoundment will initiatepond closure per the CCR Rule.
at an estimated cost of $3 million. Closure costs for existing impoundments are included in the calculation of the ARO.asset retirement obligation.
Federal Clean Water Act Section 316(b) — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. Xcel Energy estimates the likely future cost for complying with impingement and entrainment requirements is approximately $39 million, to be incurred between 2022 and 2028. Xcel Energy believes 6 NSP-Minnesota plants and 2 NSP-Wisconsin plants could be required to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $192 million. Xcel Energy anticipates these costs will be fully recoverable through regulatory 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 that would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether sulfur dioxide emission reductions beyond those required in the BART alternative rule referenced above are needed at Tolk under the “reasonable progress” requirements. As states are now proceeding with the second regional haze planning period, the EPA may choose not to act on the remanded rule, but could impose additional requirements as part of a BART reconsideration or as part of the second planning period.
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 March 31 | | Three Months Ended March 31 |
(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 | | $ | 58 | | | $ | 46 | | PPA capacity payments | | $ | 63 | | | $ | 58 | |
Other operating leases (a) | Other operating leases (a) | | 8 | | | 8 | | Other operating leases (a) | | 13 | | | 8 | |
Total operating lease expense (b) | Total operating lease expense (b) | | $ | 66 | | | $ | 54 | | Total operating lease expense (b) | | $ | 76 | | | $ | 66 | |
Finance leases | Finance leases | | | | | Finance leases | | | | |
Amortization of ROU assets | Amortization of ROU assets | | $ | 2 | | | $ | 3 | | Amortization of ROU assets | | $ | 1 | | | $ | 2 | |
Interest expense on lease liability | Interest expense on lease liability | | 4 | | | 5 | | Interest expense on lease liability | | 4 | | | 4 | |
Total finance lease expense | Total finance lease expense | | $ | 6 | | | $ | 8 | | Total finance lease expense | | $ | 5 | | | $ | 6 | |
(a)Includes short-term lease expense of $1 million and $1of $1 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 March 31, 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 | | $ | 1,592 | | | $ | 201 | | | $ | 1,793 | | | $ | 253 | | Total minimum obligation | | $ | 1,348 | | | $ | 178 | | | $ | 1,526 | | | $ | 239 | |
Interest component of obligation | Interest component of obligation | | (248) | | | (37) | | | (285) | | | (178) | | Interest component of obligation | | (197) | | | (32) | | | (229) | | | (167) | |
Present value of minimum obligation | Present value of minimum obligation | | $ | 1,344 | | | 164 | | | 1,508 | | | 75 | | Present value of minimum obligation | | $ | 1,151 | | | 146 | | | 1,297 | | | 72 | |
Less current portion | Less current portion | | (221) | | | (4) | | Less current portion | | (203) | | | (4) | |
Noncurrent operating and finance lease liabilities | Noncurrent operating and finance lease liabilities | | $ | 1,287 | | | $ | 71 | | Noncurrent operating and finance lease liabilities | | $ | 1,094 | | | $ | 68 | |
(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 approximatelyapproximately 4,037 MW and 4,062 MW of capacity under long-term PPAs at both March 31, 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 consolidated 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 provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions.agreements. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of March 31, 20212022 and Dec. 31, 2020,2021, Xcel Energy Inc. and its subsidiaries had 0no 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 $61 million and $60 million at March 31, 20212022 and Dec. 31, 2020, respectively.2021, respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide 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’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.estimated.
| | |
11. Other Comprehensive Income (Loss) |
Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 20212022 and 2020:2021:
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2021 |
(Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
Accumulated other comprehensive loss at Jan. 1 | | $ | (85) | | | $ | (56) | | | $ | (141) | |
| | | | | | |
Losses reclassified from net accumulated other comprehensive loss: | | | | | | |
Interest rate derivatives (net of taxes of $1 and $0, respectively) (a) | | 3 | | | 0 | | | 3 | |
| | | | | | |
Net current period other comprehensive income | | 3 | | | 0 | | | 3 | |
Accumulated other comprehensive loss at March 31 | | $ | (82) | | | $ | (56) | | | $ | (138) | |
| | | Three Months Ended March 31, 2020 | | Three Months Ended March 31, 2022 | | Three Months Ended March 31, 2021 |
(Millions of Dollars) | (Millions of Dollars) | | 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 | | $ | (80) | | | $ | (61) | | | $ | (141) | | Accumulated other comprehensive loss at Jan. 1 | | $ | (75) | | | $ | (48) | | | $ | (123) | | | $ | (85) | | | $ | (56) | | | $ | (141) | |
Other comprehensive loss before reclassifications (net of taxes of $(3) and $0, respectively) | | (10) | | | 0 | | | (10) | | |
Other comprehensive gain before reclassifications (net of taxes of $1, $—, $— and $—, respectively) | | Other comprehensive gain before reclassifications (net of taxes of $1, $—, $— and $—, respectively) | | 5 | | | — | | | 5 | | | — | | | — | | | — | |
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 $0 and $0, respectively) (a) | | 2 | | | 0 | | | 2 | | |
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively)(b) | | 0 | | | 1 | | | 1 | | |
Net current period other comprehensive (loss) income | | (8) | | | 1 | | | (7) | | |
Interest rate derivatives (net of taxes of $1, $—, $1 and $—, respectively) (a) | | Interest rate derivatives (net of taxes of $1, $—, $1 and $—, respectively) (a) | 1 | | | — | | | 1 | | | 3 | | | — | | | 3 | |
Amortization of net actuarial loss (net of taxes of $—, $—, $— and $—, respectively) (b) | | Amortization of net actuarial loss (net of taxes of $—, $—, $— and $—, respectively) (b) | | — | | | 1 | | | 1 | | | — | | | — | | | — | |
Net current period other comprehensive income | | Net current period other comprehensive income | | 6 | | | 1 | | | 7 | | | 3 | | | — | | | 3 | |
Accumulated other comprehensive loss at March 31 | Accumulated other comprehensive loss at March 31 | | $ | (88) | | | $ | (60) | | | $ | (148) | | Accumulated other comprehensive loss at March 31 | | $ | (69) | | | $ | (47) | | | $ | (116) | | | $ | (82) | | | $ | (56) | | | $ | (138) | |
(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 in unconsolidated subsidiaries of $170$215 million and $165$208 million as of March 31, 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 March 31 | | Three Months Ended March 31 |
(Millions of Dollars) | (Millions of Dollars) | | 2021 | | 2020 | (Millions of Dollars) | | 2022 | | 2021 |
Regulated Electric | Regulated Electric | | | | | Regulated Electric | | | | |
Total revenues | | $ | 2,870 | | | $ | 2,203 | | |
| Total revenues | | Total revenues | | $ | 2,633 | | | $ | 2,870 | |
Net income | Net income | | 269 | | | 227 | | Net income | | 278 | | | 269 | |
Regulated Natural Gas | Regulated Natural Gas | | | | Regulated Natural Gas | | | |
| Total revenues | Total revenues | | $ | 647 | | | $ | 583 | | Total revenues | | $ | 1,090 | | | $ | 647 | |
Net income | Net income | | 118 | | | 91 | | Net income | | 130 | | | 118 | |
All Other | All Other | | All Other | |
Total revenues | Total revenues | | $ | 24 | | | $ | 25 | | Total revenues | | $ | 28 | | | $ | 24 | |
Net loss | Net loss | | (25) | | | (23) | | Net loss | | (28) | | | (25) | |
Consolidated Total | Consolidated Total | | | | Consolidated Total | | | |
Total revenues | Total revenues | | $ | 3,541 | | | $ | 2,811 | | Total revenues | | $ | 3,751 | | | $ | 3,541 | |
| Net income | Net income | | 362 | | | 295 | | Net income | | 380 | | | 362 | |
| | | | | | | | | | | | | | |
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 excludes (or includes) amounts that are adjusted fromadjusts 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 the net income or loss, of each subsidiary, 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 offor 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.
Forsubsidiaries.For the three months ended March 31, 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 March 31 | | | Three Months Ended March 31 | |
Diluted Earnings (Loss) Per Share | Diluted Earnings (Loss) Per Share | | 2021 | | 2020 | | Diluted Earnings (Loss) Per Share | | 2022 | | 2021 | |
PSCo | PSCo | | $ | 0.31 | | | $ | 0.24 | | | PSCo | | $ | 0.32 | | | $ | 0.31 | | |
NSP-Minnesota | NSP-Minnesota | | 0.24 | | | 0.20 | | | NSP-Minnesota | | 0.23 | | | 0.24 | | |
SPS | SPS | | 0.11 | | | 0.08 | | | SPS | | 0.10 | | | 0.11 | | |
NSP-Wisconsin | NSP-Wisconsin | | 0.06 | | | 0.06 | | | NSP-Wisconsin | | 0.09 | | | 0.06 | | |
Equity earnings of unconsolidated subsidiaries | | 0.01 | | | 0.01 | | | |
Earnings from equity method investments — WYCO | | Earnings from equity method investments — WYCO | | 0.01 | | | 0.01 | | |
Regulated utility (a) | Regulated utility (a) | | 0.73 | | | 0.60 | | | Regulated utility (a) | | 0.75 | | | 0.73 | | |
Xcel Energy Inc. and Other | Xcel Energy Inc. and Other | | (0.06) | | | (0.04) | | | Xcel Energy Inc. and Other | | (0.05) | | | (0.06) | | |
Total (a) | Total (a) | | $ | 0.67 | | | $ | 0.56 | | | Total (a) | | $ | 0.70 | | | $ | 0.67 | | |
(a) Amounts may not add due to rounding.
Summary of Earnings
Xcel Energy — Xcel Energy’s earnings increased $0.11 per share for the first quarter of 2021. Earnings primarily reflect higher electric and natural gas margins (driven by capital investment recovery and regulatory outcomes), which more than offset additional depreciation, interest charges, less AFUDC and declining sales primarily due to the impacts of COVID-19. First quarter earnings also reflect margin from proprietary commodity trading transactions, primarily entered into under Xcel Energy’s ordinary practices prior to the weather event.
PSCo — Earnings increased $0.07 per share for the first quarter of 2021, reflecting higher natural gas and electric margins (primarily capital investment recovery and regulatory outcomes), partially offset by additional depreciation and taxes (other than income taxes).
Summary of Earnings
NSP-Minnesota Xcel Energy— Xcel Energy’s GAAP first quarter diluted earnings were $0.70 per share in 2022 compared with $0.67 per share in 2021. The increase was driven by regulatory recovery of capital investment, partially offset by higher depreciation, interest expense and O&M expenses. Costs for natural gas sold and transported significantly increased in 2022 primarily due to market price fluctuations. However, fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in revenues are offset by the related variation in costs).
PSCo — Earnings increased $0.04$0.01 per share for the first quarter of 2021,2022, reflecting higher electric margin (primarilyregulatory recovery of capital investment recovery),and higher demand revenues, partially offset by increased depreciation.depreciation, O&M expenses and incremental power costs from the Comanche Unit 3 outage.
NSP-Minnesota — Earnings decreased $0.01 per share for the first quarter of 2022, as regulatory recovery of capital investment was offset by increased depreciation and O&M expenses.
SPS— Earnings decreased $0.01 per share for the first quarter of 2022, primarily due to taxes (other than income taxes) and impacts associated with Winter Storm Uri, partially offset by favorable sales.
NSP-Wisconsin — Earnings increased $0.03 per share for the first quarter of 2021,2022, reflecting the impact of regulatory rate outcomes and higher electric margin (regulatory outcomes in Texas and New Mexico),sales attributable to weather, partially offset by increased depreciation.
NSP-Wisconsin — Earnings were flat for the first quarter of 2021.higher O&M expenses.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company.company and earnings from Energy Impact Partners funds equity method investments.
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 March 31 | | |
GAAP and ongoing diluted EPS - 2020— 2021 | | $ | 0.560.67 | | | |
| | | | |
Components of change - 20212022 vs. 20202021 | | | | |
Higher electric marginrevenues, net of electric fuel and purchased power | | 0.110.08 | | | |
Lower effective tax rate (ETR) (a) | | 0.05 | | | |
Higher natural gas marginsrevenues, net of cost of natural gas sold and transported | | 0.07 | | | |
Lower ETR (a)
| | 0.06 | | | |
Higher other income (expense), net | | 0.020.04 | | | |
Higher depreciation and amortization | | (0.08)(0.06) | | | |
Lower AFUDCHigher O&M expenses | | (0.02) | | | |
Higher taxes (other than income taxes) | | (0.01) | | | |
| | | | |
Higher interest charges | | (0.01) | | | |
Higher O&M | | (0.01) | | | |
Other, net | | (0.03)(0.04) | | | |
GAAP and ongoing diluted EPS - 2021— 2022 | | $ | 0.670.70 | | | |
(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, decoupling mechanisms in Colorado and proposed sales true-up mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric utility.
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-year30 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:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31 | | |
| 2021 vs. Normal | | 2020 vs. Normal | | 2021 vs. 2020 | | | | | | |
HDD | 1.3 | % | | (5.5) | % | | 6.5 | % | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31 | | |
| 2022 vs. Normal | | 2021 vs. Normal | | 2022 vs. 2021 | | | | | | |
HDD | 9.7 | % | | 1.3 | % | | 8.1 | % | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
| | | Three Months Ended March 31 | | | Three Months Ended March 31 | |
| | 2021 vs. Normal | | 2020 vs. Normal | | 2021 vs. 2020 | | | 2022 vs. Normal | | 2021 vs. Normal | | 2022 vs. 2021 | |
Retail electric | Retail electric | $ | — | | | $ | (0.011) | | | $ | 0.011 | | | Retail electric | $ | 0.020 | | | $ | — | | | $ | 0.020 | | |
Decoupling and sales true-up | Decoupling and sales true-up | 0.002 | | | 0.006 | | | (0.004) | | | Decoupling and sales true-up | (0.010) | | | 0.002 | | | (0.012) | | |
Electric total | Electric total | $ | 0.002 | | | $ | (0.005) | | | $ | 0.007 | | | Electric total | $ | 0.010 | | | $ | 0.002 | | | $ | 0.008 | | |
Firm natural gas | Firm natural gas | 0.003 | | | (0.007) | | | 0.010 | | | Firm natural gas | 0.016 | | | 0.003 | | | 0.013 | | |
Total | Total | $ | 0.005 | | | $ | (0.012) | | | $ | 0.017 | | | Total | $ | 0.026 | | | $ | 0.005 | | | $ | 0.021 | | |
Sales — Sales growth (decline) for actual and weather-normalized sales in 20212022 compared to 2020:2021:
| | | Three Months Ended March 31 | | Three Months Ended March 31 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual (a) | Actual (a) | | | | | | | | | | | Actual (a) | | | | | | | | | | |
Electric residential | Electric residential | | 6.3 | % | | 5.1 | % | | 8.8 | % | | 4.7 | % | | 6.0 | % | Electric residential | | (1.4) | % | | 4.7 | % | | 0.3 | % | | 6.2 | % | | 1.9 | % |
Electric C&I | Electric C&I | | (4.8) | | | (6.6) | | | (7.1) | | | (1.8) | | | (5.8) | | Electric C&I | | 2.7 | | | 6.6 | | | 10.2 | | | 4.7 | | | 6.2 | |
Total retail electric sales | Total retail electric sales | | (1.0) | | | (2.9) | | | (4.3) | | | 0.2 | | | (2.4) | | Total retail electric sales | | 1.2 | | | 5.9 | | | 8.0 | | | 5.2 | | | 4.8 | |
Firm natural gas sales | Firm natural gas sales | | 4.7 | | | 0.5 | | | N/A | | 0.8 | | | 3.1 | | Firm natural gas sales | | (1.5) | | | 20.6 | | | N/A | | 22.1 | | | 6.7 | |
| | | Three Months Ended March 31 | | Three Months Ended March 31 |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-Normalized (a) | Weather-Normalized (a) | | | | | | | | | | | Weather-Normalized (a) |
Electric residential | Electric residential | | 4.9 | % | | 4.5 | % | | 3.8 | % | | 2.9 | % | | 4.4 | % | Electric residential | | (1.5) | % | | 0.4 | % | | (0.1) | % | | 0.8 | % | | (0.3) | % |
Electric C&I | Electric C&I | | (5.1) | | | (6.7) | | | (7.3) | | | (1.9) | | | (6.0) | | Electric C&I | | 2.7 | | | 5.9 | | | 10.1 | | | 4.1 | | | 5.9 | |
Total retail electric sales | Total retail electric sales | | (1.7) | | | (3.1) | | | (5.4) | | | (0.4) | | | (3.0) | | Total retail electric sales | | 1.2 | | | 4.0 | | | 7.8 | | | 3.0 | | | 3.9 | |
Firm natural gas sales | Firm natural gas sales | | (0.9) | | | (1.3) | | | N/A | | (2.7) | | | (1.2) | | Firm natural gas sales | | (1.2) | | | 5.3 | | | N/A | | 7.3 | | | 1.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31 (2020 Leap Year Adjusted) |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-Normalized (a) | | | | | | | | | | |
Electric residential | | 6.1 | % | | 5.7 | % | | 5.0 | % | | 4.0 | % | | 5.6 | % |
Electric C&I | | (4.1) | | | (5.6) | | | (6.3) | | | (0.8) | | | (5.0) | |
Total retail electric sales | | (0.6) | | | (2.0) | | | (4.3) | | | 0.7 | | | (1.9) | |
Firm natural gas sales | | 0.2 | | | (0.2) | | | N/A | | (1.5) | | | — | |
(a)Higher residential sales and lower C&I sales were primarily attributable to COVID-19.
Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)
EachWeather-adjusted sales results for each of our utility subsidiaries experienced higher residential sales and lower C&I salesin 2022 reflect generally improving economies as a resultthe adverse effects of COVID-19 beginninglessen. The recovery reflects increased sales in March 2020. In addition, the following items impacted sales:C&I sector due to increased economic activity. Individuals returning to work have led to declines in use per customer and overall residential sales.
•PSCo — Residential sales rosedeclined based on an increased number ofdecreased use per customer, partially offset by a 1.2% increase in customers. The growth in C&I sales was due to a 1.3% increase in customers and higher use per customer. The decline in C&I sales wascustomer, primarily due to decreases in the manufacturingreal estate and service industries, partially offset by an increase in theleasing, food services, energy sector.and construction sectors.
•NSP-Minnesota — Residential sales growth reflects highera 1.2% increase in customers, partially offset by decreased use per customer and increased customer additions.customer. The declinegrowth in C&I sales was primarily due to decreases withinhigher use per customer, particularly in the manufacturing, real estate and leasing, and food service sectors.
•SPS — Residential sales declined due to a lower use per customer, partially offset by a 1.0% increase in customers. C&I sales increased due to customer growth and higher use per customer. The decline in C&I sales wascustomer, primarily driven by decreases within the energy and manufacturing sectors.sector.
•NSP-Wisconsin — Residential sales growth was attributable to customer additionsa 0.7% increase in customers. The growth in C&I sales was due to a 0.4% increase in customers and higher use per customer. The decline in C&I sales was largely related to decreasescustomer, primarily led by increases in the energymanufacturing, accommodation and manufacturing industries, partially offset by an increase in the service sector.food services and health care sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)
•Natural gas sales primarily reflect lowera higher customer use, offset by anprimarily in NSP-Minnesota and NSP-Wisconsin, as well as a 1.2% increase in the number ofresidential customers and a 0.5% increase in C&I customers.
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 reducedreduce electric revenue and marginincome taxes.
Electric revenues, fuel and purchased power and electric margin:
| | | Three Months Ended March 31 | | | Three Months Ended March 31 | |
(Millions of Dollars) | (Millions of Dollars) | | 2021 | | 2020 | | (Millions of Dollars) | | 2022 | | 2021 | |
Electric revenues | Electric revenues | | $ | 2,870 | | | $ | 2,203 | | | Electric revenues | | $ | 2,633 | | | $ | 2,870 | | |
Electric fuel and purchased power | Electric fuel and purchased power | | (1,386) | | | (797) | | | Electric fuel and purchased power | | (1,094) | | | (1,386) | | |
Electric margin | Electric margin | | $ | 1,484 | | | $ | 1,406 | | | Electric margin | | $ | 1,539 | | | $ | 1,484 | | |
Changes in electric margin:Change:
| | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended March 31, 20212022 vs. 20202021 | | |
Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, Texas and New Mexico) | | $ | 63 | | | |
Non-fuel riders | | $ | 4436 | | | |
Regulatory rate outcomes (Colorado, Texas, New Mexico, WisconsinSales and North Dakota)demand(a)
| | 22 | | | |
Conservation and demand side management (offset in expense) | | 4414 | | | |
| | | | |
Proprietary commodity trading, net of sharing | | 27 | | | |
Wholesale transmission revenue (net) | | 11 | | | |
Estimated impact of weather (net of decoupling/sales true-up) | | 56 | | | |
PTCs flowed back to customers (offset by lower ETR) | | (37)(53) | | | |
| | | | |
Proprietary commodity trading, net of sharing(b) | | (25) | | | |
Sales and demandComanche Unit 3 outage ((a)c)
| | (14)(9) | | | |
Other (net) | | (2)1 | | | |
Total increase in electric margin | | $ | 7855 | | | |
(a)Sales excludes weather impact, net of decoupling/decoupling in Colorado and proposed sales true-up and demand is netmechanism in Minnesota.
(b)Includes $27 million of sales true-up.trading margin recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri.
(c)See Other section for further information.
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 expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas hasgenerally have minimal earnings impact on natural gas margin due to cost recovery mechanisms.
Natural gas revenues, cost of natural gas sold and margin:
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31 | | |
(Millions of Dollars) | | 2021 | | 2020 | | | | |
Natural gas revenues | | $ | 647 | | | $ | 583 | | | | | |
Cost of natural gas sold and transported | | (299) | | | (285) | | | | | |
Natural gas margin | | $ | 348 | | | $ | 298 | | | | | |
Changes intransported and natural gas margin:
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31 | | |
(Millions of Dollars) | | 2022 | | 2021 | | | | |
Natural gas revenues | | $ | 1,090 | | | $ | 647 | | | | | |
Cost of natural gas sold and transported | | (710) | | | (299) | | | | | |
Natural gas margin | | $ | 380 | | | $ | 348 | | | | | |
Change:
| | | | | | | | | | |
(Millions of Dollars) | | Three Months Ended March 31, 20212022 vs. 20202021 | | |
Regulatory rate outcomes (Colorado)(Minnesota, Wisconsin, North Dakota) | | $ | 4017 | | | |
Estimated impact of weather | | 710 | | | |
Gas sales and transport (excluding weather impact) | | 7 | | | |
| | | | |
| | | | |
Other (net) | | 3 (2) | | | |
| | | | |
| | | | |
Total increase in natural gas margin | | $ | 5032 | | | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $5$18 million or 0.9%, for the first quarter, of 2021. The increase was primarily due to additional investments in technology and customer programs, higher insurance premiums and additional bad debt expenses associated with new wind farms, software and infrastructure costs, compensation, damage prevention and storms,(primarily attributable to higher billings and/or increased commodity prices), partially offset by continuous improvement initiatives.a reduction in employee benefit costs.
Depreciation and Amortization — Depreciation and amortization increased $58$41 million or 12.5%, for the first quarter of 2021.quarter. The increase was primarily driven by several wind farms going into service as well asand normal system expansion. In addition, 2021 depreciation expense increased as a result of implementation of new depreciation rates in Colorado, New Mexico and Texas.
Other Income (Expense) — Other income (expense) increased $16 million for the first quarter of 2021, largely related to rabbi trust performance primarily offset in O&M expenses (compensation).
AFUDC, Equity and Debt — AFUDC decreased $14 million for the first quarter of 2021. Decrease was driven by various wind projects placed into service.
Interest Charges — Interest charges increased $6$9 million or 3.0%, for the first quarter, of 2021. The increase was largely attributabledue to higherincreased long-term debt levels to fund capital investments partially offset by lower long-term and short-term interest rates.the unrecovered/deferred balances related to Winter Storm Uri.
Income Taxes — Income tax benefit increased $16$28 million for the first quarter, of 2021. The increase was primarily driven by an increase in wind PTCs due to additional wind facilities going into service.PTCs. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. Impact of wind PTCs was partially offset by higher pretax earnings in 2021.
Winter Storm Uri
In mid-February 2021,April 2022, the central portion of the United States experienced a major winter storm (Winter Storm Uri). Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation across the region. The cold weather also affected the country’s supply and demand for natural gas. TheseIRS published inflation factors contributed to extremely high market prices for natural gas and electricity. In addition, NSP-Minnesota’s three peak shaving plants, which are used to ensure system reliability under Design Day conditions, have been unavailable since early 2021 due to required repairs to address safety concerns withdetermine the units. Despite the extreme conditions, Xcel Energy’s customers experienced minimal disruptions as a result of preemptive infrastructure investments and the response of our employees.
PTC rate. As a result, the 2022 PTC rate on the sale of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $965 million (largely deferred as regulatory assets). The utility subsidiaries mitigated the customer impact by approximately $190 million primarily through sales of excess generation.
The estimated net impact was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | Natural Gas for Distribution | | Natural Gas for Electric Generation | | Other Electric Generation | | Subtotal Costs | | Net Market Settlements (a) | | Total Impact |
NSP-Minnesota | | $ | 250 | | $ | 5 | | | $ | 15 | | | $ | 270 | | | $ | (40) | | | $ | 230 | |
NSP- Wisconsin | | 45 | | — | | | — | | | 45 | | | — | | | 45 | |
PSCo | | 305 | | 315 | | | 5 | | | 625 | | | (15) | | | 610 | |
SPS | | — | | 200 | | | 15 | | | 215 | | | (135) | | | 80 | |
Total | | $ | 600 | | $ | 520 | | | $ | 35 | | | $ | 1,155 | | | $ | (190) | | | $ | 965 | |
(a) Net market settlements includes purchases of energy and other charges to serve our customers as well as sales of energy facilitated through ISOs or bilateral transactions, each subject to mechanisms for recovery and sharing with our customers.
In addition, higher market prices resulted in $27 million of net gains (after customer sharing) related to proprietary commodity trading. These transactions were primarily entered into under Xcel Energy’s ordinary trading practices prior to Winter Storm Uri.
Certain energy transactions are subject to final ISO re-settlement calculations and the impacts of credit losses shared among market participants. Such adjustments are not expected to be material to our results of operations, financial condition or cash flows.
Regulatory Overview —Xcel Energy has natural gas, fuel and purchased energy mechanisms in each jurisdiction for the purpose of 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 two years in order to significantly mitigate the impact to customer bills. Additionally, we are not requesting recovery of associated financing costs in order to further limit the impact to our customers.
The following proceedings have been initiated:
| | | | | | | | |
Utility Subsidiary | Jurisdiction | Regulatory Status |
NSP-Minnesota | Minnesota | NSP-Minnesota has filed its report with the MPUC detailing its preparedness and actions during the storm and proposing recovery of incremental costs from natural gas customers over 24 months with no financing charge. Comments are due in May 2021. |
| South Dakota | In April, NSP-Minnesota filed a letter with the South Dakota Public Utilities Commission noting that we were a net seller in the market, resulting in lower fuel clause costs. |
| North Dakota | NSP-Minnesota has filed its report with the North Dakota Public Service Commission detailing its preparedness and actions during the storm and proposing recovery of incremental costs from natural gas customers over 24 months with no financing charge. |
NSP-Wisconsin | Wisconsin | In March, the PSCW staff determined the natural gas costs incurred during the storm were prudent and approved NSP-Wisconsin's proposal to recover these costs over a nine-month period through December 2021 with no financing charge. |
| Michigan | In March, NSP-Wisconsin filed testimony in the pending gas recovery plan proceeding to address $2 million of under-recovery associated with Winter Storm Uri. |
PSCo | Colorado | PSCo filed an initial response with the CPUC in March. In May 2021, PSCo intends to file a plan to recover the weather-related costs over 24 months with no financing charge. |
SPS | Texas | SPS intends to file for a surcharge in the second quarter to recover fuel costs over 24 months with no financing charge. Prudence of fuel costs will be subject to review in SPS' upcoming fuel reconciliation case. |
| New Mexico | The NMPRC approved SPS' requested fuel mechanism variance to permit recovery over 24 months with no financing charge (subject to NMPRC review). |
To enhance liquidity and for the ability to propose recovering the increased fuel costs over a longer time period (i.e., mitigate customer bill impacts), Xcel Energy Inc. entered into a $1.2 billion 364-Day Term Loan Agreement and increased the size of its previously planned debt issuances at the utility subsidiaries.
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 duration and magnitude of business restrictions, re-shut downs and the level and pace of economic recovery.
An overview of certain risk considerations or areas which have or could significantly impact uselectricity produced from wind is as follows.
Sales — Xcel Energy has experienced and may continue to experience higher residential sales and lower 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 as2.7 cents per kilowatt hour, 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. As part of NSP-Minnesota’s stay-out alternative, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related costs.
The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve.2.5 cents for 2021.
| | |
Public Utility Regulation and Other |
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI.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, 20202021 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 North Dakota Electric Rate Case | | $19 | | November 2020 | | Pending |
2020 TCR Electric Rider | | 82 | | November 2019 | | Pending |
2020 GUIC Natural Gas Rider | | 21 | | November 2019 | | Received |
2021 GUIC Natural Gas Rider | | 27 | | October 2020 | | Pending |
2020 RES Electric Rider | | 107 | | November 2019 | | Received |
2021 RES Electric Rider | | 189 | | November 2020 | | Pending |
Additional Information:
20202022 Minnesota Electric Rate Case and Stay-Out Alternative —In November 2020, NSP-Minnesota filed an electric rate case seeking a $597 million revenue increase over three years with the MPUC. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing. I
In December 2020, the MPUC verbally approved the stay-out alternative petition, which includes the extension of the sales, capital and property tax true-up mechanisms and delays any increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 2022.
Additionally, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related expenses, including bad debt expense, and committed to fund $18 million in a Residential Payment Plan Credit Program or other similar customer relief programs, as directed by the MPUC. NSP-Minnesota also agreed to an earnings test in which all earnings above an ROE of 9.06% in 2021 would be refunded to customers.
In Februaryn October 2021, NSP-Minnesota filed a letter highlighting a change in the calculation of its total deficiency and interim rates included in its November 2020 filing. This adjustment would have reduced the filed deficiency and interim rates by approximately $43 million should the rate case have proceeded, but has no impact on the stay-out alternative petition.
In April 2021, the MPUC issued an order approving NSP-Minnesota’s proposed changes and a requirement to withdraw NSP-Minnesota’s notice of change in rates, as well as establishing a comment period allowing parties to address the changes discussed in the February letter.
2020 North Dakota Electric Rate Case — In November 2020 and revised in March 2021, NSP-Minnesota filed athree-year electric rate case with the North Dakota Public Service Commission. NSP-MinnesotaMPUC. The rate case is requestingbased on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years.
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 December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022.
Next steps in the procedural schedule are expected to be as follows:
•Intervenor testimony: Oct. 3, 2022.
•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 in annual retail electric revenues of approximately $19 million.$36 million, or 6.6%. The rate filing is based on a 20212022 forecast test year and includes a requested ROE of 10.2%10.5%, an equity ratio of 52.5% and an electrica rate base of approximately $677$934 million.
In December 2021, the MPUC approved interim rates of $25 million, subject to refund, effective Jan. 1, 2022.
Next steps in the procedural schedule are expected to be as follows:
•Intervenor testimony: Aug. 30, 2022.
•Rebuttal testimony: Oct. 4, 2022.
•Hearing: Nov. 1-4, 2022.
•ALJ Report: Feb. 6, 2023.
•MPUC Order: April 26, 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 10.5%. 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 $124 million. Interim rates of $7 million, subject to refund, of approximately $16 million were implemented in January 2021 and subsequently revised to $13 million, effective Aprilon Nov. 1, 2021.
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR RiderApril 2022, NDPSC Staff recommended a $4 million increase, based on an ROE of 9.06%9.5% and an equity ratio of 52.0%. In April 2022, NSP-Minnesota updated its request to $6 million, or 8.8% based on a requested ROE of 10.5%, an equity ratio of 52.54% and an updated rate base of $115 million. Hearings are expected June 1-3, 2022. An MPUCNDPSC decision is pending.
2020 GUIC Natural Gas Rider — In April 2021,expected in the MPUC approved the 2020 GUIC Rider, based on an ROEthird quarter of 9.04%.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2020 RES Electric Rider — In November 2019, NSP-Minnesota filed the RES Rider. In March 2021, the MPUC voted to approve revenue requirements of $41 million for 2019 and $66 million for 2020. The filing included an ROE of 9.06%. The new rate will be implemented after the Commission Order is issued.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount includes a true-up for the 2019 and 2020 rider of $96 million and the 2021 requested amount of $93 million. The filing included an ROE of 9.06%. An MPUC decision is pending.
Minnesota Resource Plan —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan is expected to result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050.2022.
In June 2020, NSP-Minnesota filed a supplement to its resource plan. The updated preferred resource plan reflects the following:
•Retirement of 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 the 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 through current end of life (2033 and 2034).
•Construction of the Sherco combined cycle natural gas plant.
•The addition of 3,500 MW of solar.
•The addition of 2,250 MW of wind.
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.).
•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.
Initial comments were submitted Feb. 11, 2021 and reply comments are due June 25, 2021. The MPUC is anticipated to make a final decision during 2021.
Minnesota Relief and Recovery — 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.
In January 2021,The status of the MPUC approved the repowering of 651 MW of owned wind projects and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years.
NSP-Minnesota’s remaining proposal (revised in April 2021) includes the following:various proposals is listed below:
•Acquire 120In April 2021, NSP-Minnesota proposed to add 460 MW repowered wind farm and buy-out of the remaining PPA from ALLETE for $210 million. An MPUC decision was requested by July 29, 2021.
•Add solar facilities of 460 MW at the Sherco site with an incremental investment of approximately $575 million. See further discussion within Sherco Solar Project below.
•Provide $150In March 2022, the MPUC approved the public charging proposal for 21 sites and asked NSP-Minnesota to develop a proposal for additional investments in public charging infrastructure, but denied NSP-Minnesota’s proposal to provide $40 million of incremental electric vehicle rebates.
The MPUC is expectedrebates due to address the solar facility, ALLETE repower acquisition and the electric vehicle proposal in the second half of 2021.concerns regarding legal authority.
Minnesota State ROFR Statute ComplaintResource Plan Settlement — In September 2017, LSP TransmissionJuly 2019, NSP-Minnesota filed a complaint inits Minnesota (Upper Midwest) resource plan, which runs through 2034. In February 2022, the Minnesota District Court againstMPUC approved the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning a transmission project to NSP-Minnesota and ITC Midwest, LLC as the incumbent utilities, consistent with a Minnesota state ROFR statute.following:
The complaint challenged•10-year extension for the constitutionalityMonticello nuclear facility.
•Retirement of the statuteA.S. King plant in 2028 and is seeking declaratory judgment thatSherco 3 in 2030.
•NSP-Minnesota ownership of Sherco and A.S. King gen-tie lines plus additional renewable resources on the statute violates the Commerce Clauselines up to its current interconnection rights (2,000 MW for Sherco and 600 MW for A.S. King).
•The need for 2,150 MW of new wind and 2,500 MW of new solar by 2032, as well as additional renewable generation of 1,100 MW beyond 2032.
•Recognition of the U.S. Constitutionneed for 800 MW of additional firm dispatchable resources between 2027 and should not be enforced.2029. The dispatchable generation will require an approval through a certificate of need process.
2022 RES Electric Rider — In June 2018,November 2021, NSP-Minnesota filed the Minnesota District Court granted Minnesota state agenciesRES Rider. The requested amount of $264 million includes a true-up (2020 and NSP-Minnesota’s motions to dismiss with prejudice. In February 2020, the Eighth Circuit Court2021 riders) of Appeals upheld the Minnesota District Court decision to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission’s petition for rehearing. On March 1, 2021, the Supreme Court denied review$154 million and the appeals process has ended.2022 requested amount of $110 million. The filing included an ROE of 9.06%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The amount of $189 million included a true-up (2019 and 2020 riders) of $96 million and a 2021 amount of $93 million. The filing was based on an ROE of 9.06%. The rider was approved by the MPUC in March 2022.
2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on an ROE of 9.04%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on an ROE of 9.04%. An MPUC decision is pending.
2022 TCR Electric Rider — In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million based on an ROE of 9.06%. An MPUC decision is 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-Wisconsin
Recently Concluded Regulatory Proceedings
NSP-Wisconsin Solar ProposalMichigan Electric Rate Case — In October 2020,March 2022, the Michigan Public Service Commission approved a settlement that grants NSP-Wisconsin filed foran electric revenue increase of $1.6 million in 2022, based on a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A PSCW decision is expected in the third quarterROE of 2021.9.7% and an equity ratio of 52.5%. New rates were effective April 1, 2022.
PSCo
Pending and Recently Concluded Regulatory Proceedings
Colorado Natural Gas Rate Case —In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the PSIA rider. The request is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022.
Additionally, PSCo’s request includes step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.
| | | | | | | | |
Revenue Request (millions of dollars) | | 2022 |
Changes since 2020 rate case: | | |
Plant related investments (a) | | $ | 210 | |
Operations and maintenance, amortization and other expenses | | 11 | |
Property tax expense | | 11 | |
Sales growth | | (17) | |
Net increase to revenue | | 215 | |
Previously authorized costs: | | |
Transfer of costs previously recovered through the PSIA rider | | (108) | |
Total base revenue request | | $ | 107 | |
| | |
Proceeding | | Amount (in millions) | | Filing Date | | Approval |
Wildfire Protection RiderProjected 2022 year-end rate base (billions of dollars) | | $325 | | July 20203.6 | | Concluded |
PSIA Extension | | $464 | | Feb. 2021 | | Pending |
Additional Information:(a) Includes approximately $28 million as a result of the increase in ROE from 9.2% to 10.25%.
Next steps in the procedural schedule are expected to be as follows:
Wildfire Protection Rider •—Intervenor testimony: June 15, 2022.
•Rebuttal testimony: July 13, 2022.
•Settlement: Aug. 3, 2022.
•Evidentiary hearings: Aug. 17-23, 2022.
•Statement of position: Sept. 21, 2022.
Colorado Electric Rate Request — In 2020,July 2021, PSCo requested to establishfiled a rider to recover incremental costs associatedrequest with system investments to reduce wildfire risk, projected to be approximately $325 million from 2021 to 2025. In February 2021, the Administrative Law Judge issued a recommended decision approving the wildfire mitigation program as it was in the public’s interest, but denied PSCo’s rider request in favor of deferred accounting with ultimate recovery in a future rate case. In April 2021, the CPUC accepted the Administrative Law Judge’s recommended decision.
Forecasted annual revenue requirements from 2021 through 2025:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 |
Forecasted annual revenue requirement | | $ | 17 | | | $ | 24 | | | $ | 29 | | | $ | 32 | | | $ | 34 | |
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. 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. A CPUC decision is expected in the fourth quarter of 2021.
2019 Phase 1 Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a reviewnet electric rate increase of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. A decision is pending.
2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal of the CPUC’s ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018)$343 million (or 12.4%). The appeal requested reviewtotal request reflects a $470 million increase, which includes $127 million of the following: denialpreviously authorized costs currently recovered through various rider mechanisms. The request was 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 return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology.new depreciation study.
In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but it upheld2022, the CPUC treatmentapproved an unopposed settlement without modification. Rates became effective April 1, 2022. Key settlement terms include:
•A net electric rate increase of $177 million. The total change in base rates is $299 million, which includes $122 million of revenue previously collected through various rider mechanisms.
•A ROE of 9.3% and an equity ratio of 55.69%.
•A current 2021 test year (average rate base) with the transfer of Cheyenne Ridge, the Wildfire Mitigation Plan and Advanced Grid Intelligence and Security investments at year-end rate base.
•Approval of all of PSCo’s proposed depreciation adjustments.
•Continuation of the retiree medical assetsproperty tax, qualified pension, and non-qualified pension trackers.
•Continuation of Advanced Grid Intelligence and Security deferral including interest equivalent to PSCo's weighted average cost of capital structure methodology. once the balance exceeds $50 million.
•Continuation of the Wildfire Mitigation Plan deferral, with a debt return.
Colorado Power Pathway Settlement— In February 2021,2022, the CPUC approved 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 Performance Incentive Mechanism 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. Key details of the Performance Incentive Mechanisms are pending the CPUC’s written decision.
•The CPUC granted a conditional CPCN 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 April 2022, PSCo and multiple intervenors filed a motion to implement the District Court’s decision on treatmentrevised settlement of the prepaid pension asset forresource plan, which will result in the applicable periodfurther acceleration of Jan. 1, 2018 through Oct. 31, 2020.the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. A CPUC decision is expected beforein the endsecond 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 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 comprehensive settlement with the CPUC Staff and the Colorado Energy Office, which proposed 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 Utility Consumer Advocate has not signed the settlement. A hearing and a CPUC decision on the settlement is expected in the second quarter of 2022.
Key settlement terms include:
•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 no carrying charges through a rider mechanism. Recovery will likely commence in Q2 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 (approved by the CPUC in February 2022 as part of the 2020 retail electric commodity adjustment settlement agreement).
•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 Dec. 31, 2021.
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 a subset of 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, with a CPUC decision due in the second quarter of 2021. As of March 31, 2021,2022, PSCo has recognized a refund for Residential customers and a surcharge for C&I customers based on its estimate2020, 2021 and the first quarter of final 2020 amounts.2022 results.
Colorado’s Power Pathway Transmission ExpansionIn October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of decoupling. See Partial Settlement disclosure above.
Comanche Unit 3 — In MarchOctober 2021, PSCo fileda comprehensive settlement was reached, which addressed treatment of 2020 Comanche Unit 3 replacement power costs. See Colorado Partial Settlement disclosure above and Note 10 accompanying the consolidated financial statements for a Certificate of Public Convenience and Necessity for the Power Pathway transmission project. Xcel Energy proposed a 560-mile, 345 kilovolt double circuit transmission network to enable 5,500 MW of renewable generation in eastern Colorado with an estimated cost of approximately $1.7 billion. PSCo also presented an extension of the Power Pathway project into southeast Colorado, referred to as the May Valley - Longhorn Extension ($0.3 billion). PSCo expects future filings for related network upgrades, voltage support and interconnection facilities, which with the May Valley - Longhorn Extension, could result in an incremental investment of $0.5 - $1 billion. A CPUC decision regarding the Power Pathway project, as well as the May Valley - Longhorn Extension, is expected in late 2021.further information.
PSCo KEPCO Filing —2019 Electric Rate Case Appeal — In SeptemberAugust 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC for approvaldecisions on gains and losses on sales of assets, oil and gas royalty revenues, Board of Directors equity compensation and a true-up surcharge to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminatingcollect the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the third quarter of 2021.
Electric Resource Plan —difference between rates from February through August 2020. In March 2021,January 2022, the Denver District 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 filed its 2021 Electric Resource Plan withand set aside and remanded the CPUC. Theissue for further consideration. PSCo anticipates filing outlines the proposed future retirements/conversionsa Motion for Decision in Q2 2022.
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).
•1,200 MW of distributed generation solar resources.Contents
The preferred plan proposes to create a 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.
A CPUC decision on the resource plan is expected by the end of 2021 (Phase I) with the competitive solicitation for resource additions expected in 2022 (Phase II). Incremental generation system costs to meet carbon emission reduction targets are proposed to be recovered through a statutorily-authorized Clean Energy Plan Rider.
PSCoGCA NOPR — Comanche Unit 3 — PSCo is part ownerIn June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR matter and operator of Comanche Unit 3,proposed a 750 MW, coal-fueled electric generating unit. In January 2020,2 step process aimed at 1) considering near term process changes to the unit experienced a turbine failure causing the unitGCA used by various utilities to be taken offline for repairs, which were completed in June 2020. During start-up the unit experiencedfiled no later than July 1, 2022 and 2) a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expectedlonger term process to evaluate potential performance incentive GCA structures to be recovered through insurance policies. PSCo incurred replacement power costs of approximately $16 million during the outage.filed no later than Nov. 1, 2022.
In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance was issued in March 2021. The CPUC Staff’s report noted higher-than average outages and included some 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 February 2021, the joint owners of Comanche Unit 3 (Intermountain Rural Electric Association and Holy Cross Electric) served PSCo with a Notice of Claim related to Comanche Unit 3's operation and availability. Discussions are proceeding pursuant to a contractual dispute resolution process and the amount of any alleged damages depends on multiple factors and is currently unknown.
SPS
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | |
Proceeding | | Amount (in millions) | | Filing Date | | Approval |
2021 New Mexico Electric Rate Case | | $88 | | January 2021 | | Pending |
2021 Texas Electric Rate Case | | $143 | | February 2021 | | Pending |
Additional Information:
2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC seeking an increase inwith a current requested base rates of approximately $88 million. SPS' net rate increase of $84 million.
In February 2022, the NMPRC approved an uncontested stipulation without modification, which reflected a $62 million rate increase, a change in the depreciation life of the Tolk coal plant to New Mexico customers is expected to be approximately $48 million, or 10%, as a result of offsetting fuel cost reductions and PTCs from the Sagamore wind project. PTCs are being credited to customers through the fuel clause.
The request is based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%,2032, an equity ratio of 54.72% and retail rate basea ROE of approximately $1.9 billion.
The request includes9.35% for reconciliation statements and determining the revenue requirements for the Sagamore and Hale wind projects. New rates went into effect of approximately 400 MW of reduced peak load in 2021 from a wholesale transmission customer and changes to depreciation lives of SPS’ Tolk coal-fired power plant (from 2037 to 2032) and the coal handling assets at the Harrington facility (to 2024).
The procedural schedule is expected to be as follows:
•Staff and intervenor testimony — May 17, 2021.
•Rebuttal testimony — June 9, 2021.
•Deadline to file stipulation — June 23, 2021.
•Public hearing or hearing on stipulation — JulyFeb. 26, - Aug. 6, 2021.
•End of nine month suspension — Nov. 3, 2021.
A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.2022.
2021 Texas Electric Rate Case — In February 2021, SPSfiled an electric rate case with the PUCT and its municipalities with original rate jurisdiction seeking an increase in base rates of approximately $143$140 million. SPS' net rate increase to Texas customers is expected to be approximately $74 million, or 9.2%, as a result of offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
The request iswas based on ana ROE of 10.35%, an equity ratio of 54.60% (based on actual capital structure), a Texas retail rate base of approximately $3.3 billion and a historic test year based on the 12-month period12-months ended Dec. 31, 2020.
The request includes the effect of losing approximately 400 MW fromIn January 2022, SPS and intervenors filed a wholesale transmission customer and changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets of the Harrington facility (to 2024).
The procedural schedule is expected to be as follows:blackbox settlement. Key terms include:
•Intervenor testimony — Aug. 13, 2021.
•Staff testimony — Aug. 20, 2021.
•Rebuttal testimony — Sept.Base rate increase of $89 million effective back to March 15, 2021.
•Public hearing — Oct. 18 - Oct. 28, 2021.A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.
Once final•Depreciation lives for Tolk moved up to 2034 and Harrington coal assets moved up to 2024.
In February 2022, the ALJ issued an order approving interim rates are approved, a surcharge will be requested fromeffective March 15, 2021 through the effective date of new base rates.1, 2022. A PUCT decision is expected in the firstsecond quarter of 2022.
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. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the availability of materials and has sought to mitigate impacts by seeking alternative suppliers as necessary.
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.
The uncertainty of the investigation and the adverse impact on potential tariffs has resulted in the cancellation or delay of certain domestic solar projects.
The impacts on Xcel Energy are as follows:
Texas State ROFR Litigation •NSP-Minnesota Sherco Solar Project— In April 2021, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an initial estimated investment of approximately $575 million. NSP-Minnesota requested a delay in the procedural schedule due to recent solar supply chain disruptions and potential impact on pricing. We now anticipate a MPUC decision in Q4 2022 or Q1 2023. The proposed facilities are still expected to be in-service by the end of 2025.
•In May 2019, the Governor signed a ROFR bill into law, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility.NSP-Wisconsin — In June 2019,2021, the Public Service Commission of Wisconsin approved NSP-Wisconsin’s Western Mustang solar project, a complaint74 MW facility that would be built by a developer for approximately $100 million. The project was originally scheduled to go into service in 2022. As a result of the disruption of the solar supply chain, the developer has indicated difficulty delivering the project at the contract price and scheduled in-service date. Negotiations on a potential solution are on-going.
•PSCo PPAs— PSCo has several solar PPAs scheduled to go into service in late 2022 and early 2023. Some developers have indicated difficulty delivering the projects at the contract price and at the scheduled in-service date. Negotiations on a potential solution are on-going. PSCo is developing contingency plans in the event that the PPAs are not completed in time to meet the capacity needs of the 2023 summer season.
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.
On March 31, 2022, a class action suit was filed in Boulder County pertaining to the United States District Court forMarshall Fire. In the Western Districtremote 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 Texas claimingoperations or cash flows.
Comanche Unit 3 Outage
In January 2022, PSCo experienced an extended outage at the new ROFR lawComanche Unit 3 plant (750 MW, coal-fueled electric generating unit).PSCo will not seek recovery of any incremental replacement power costs, which are estimated to be unconstitutional. In February 2020, the federal court complaint was dismissed by the district court. Inapproximately $25 million, assuming normal weather, current market pricing and remediation in June 2022. Incremental replacement power costs incurred as of March 2020, the district court ruling was appealed to the Fifth Circuit. A decision is pending.31, 2022 were $9 million.
New Mexico FPPCAC Continuation —
In December 2020, the Hearing Examiner recommended the NMPRC approve SPS’ request for the continued use of the FPPCAC and the reconciliation of its fuel costs for the reporting period (September 2015 through June 2019). Additionally, the Hearing Examiner recommended the NMPRC deny the proposed Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel and purchased power costs.
Winter Storm Uri
In February 2021, the NMPRC approvedUnited States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the Hearing Examiner’s recommended decision without modification.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 $1 billion (largely deferred as regulatory assets).
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 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 63 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers. Xcel Energy currently has approval for recovery of Winter Storm Uri costs in Wisconsin, Michigan, North Dakota and New Mexico. There were no material costs for South Dakota.
A summary of the pending regulatory requests for Winter Storm Uri cost recovery in the other states is listed below.
Proceedings initiated: | | | | | | | | |
Utility Subsidiary | Jurisdiction | Regulatory Status |
NSP-Minnesota | Minnesota | In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021. 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. The $179 million in extraordinary cost recovery is subject to refund pending the outcome of a contested case before an ALJ.
In December 2021, direct testimony was received from intervenors. A hearing before the ALJs took place in February 2022. The Company and intervenors subsequently submitted briefs. The DOC recommended that NSP-Minnesota be disallowed $122 million in costs. The OAG modified its position, recommending disallowances of $110 million to $148 million, and the CUB continues to recommend a $69 million disallowance.
Xcel Energy strongly disagrees with the recommendations of the DOC, OAG and CUB and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. An ALJ decision is expected in late May and an MPUC decision is expected in Q3 of 2022. |
| | | | | | | | |
Utility Subsidiary | Jurisdiction | Regulatory Status |
PSCo | Colorado | In 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.
In October, a partial settlement was reached with the Staff and the Colorado Energy Office, allowing full recovery of Winter Storm Uri deferred costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with no carrying charges. A CPUC decision on the settlement is pending.
The statutory date for decision is July 15, 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery. |
SPS | Texas | In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing.
In January 2022, SPS and other parties filed a stipulation for interim rates. The filing covers all fuel under-collections occurring between January 2020 and August 2021, totaling $121 million. The settlement does not address the prudence of Winter Storm Uri costs nor the retention of $11 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. Interim rates, designed to collect up to $110 million over a period of 30 months, began on Feb. 1, 2022. |
Environmental RegulationAffordable Clean Energy
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans by 2022 for greenhouse gas reductions from coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants. However, the Court of Appeals decision has been appealed to the U.S Supreme Court, where the Court heard argument in February and is expected to rule by June on the nature and extent of the EPA’s greenhouse gas regulatory authority. If theany new rules require additional investment, Xcel Energy believes based on prior state commission practices, that the cost of these initiatives or replacement generation would be recoverable through rates.rates based on prior state commission practices.
| | |
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 its 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 itus 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 itsour risk management committee.
Fair value of net commodity trading contracts as of March 31, 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) | | $ | (2) | | | $ | — | | | $ | 2 | | | $ | 2 | | | $ | 2 | | NSP-Minnesota (a) | | $ | (7) | | | $ | (11) | | | $ | (3) | | | $ | (2) | | | $ | (23) | |
NSP- Minnesota (b) | NSP- Minnesota (b) | | (4) | | | 3 | | | (9) | | | (2) | | | (12) | | NSP- Minnesota (b) | | 4 | | | 4 | | | (5) | | | (5) | | | (2) | |
PSCo (a) | PSCo (a) | | 1 | | | 1 | | | — | | | — | | | 2 | | PSCo (a) | | 16 | | | 9 | | | 2 | | | 1 | | | 28 | |
PSCo (b) | PSCo (b) | | (33) | | | (46) | | | (8) | | | — | | | (87) | | PSCo (b) | | (41) | | | (45) | | | 1 | | | — | | | (85) | |
| | $ | (38) | | | $ | (42) | | | $ | (15) | | | $ | — | | | $ | (95) | | | $ | (28) | | | $ | (43) | | | $ | (5) | | | $ | (6) | | | $ | (82) | |
| | | Options Maturity | | Options 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 (b) | NSP-Minnesota (b) | | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | NSP-Minnesota (b) | | $ | 1 | | | $ | — | | | $ | — | | | $ | 11 | | | $ | 12 | |
PSCo (b) | PSCo (b) | | 21 | | | 22 | | | — | | | — | | | 43 | | PSCo (b) | | 25 | | | 24 | | | — | | | — | | | 49 | |
| | $ | 21 | | | $ | 22 | | | $ | — | | | $ | 2 | | | $ | 45 | | | $ | 26 | | | $ | 24 | | | $ | — | | | $ | 11 | | | $ | 61 | |
(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 three months ended March 31:
| (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 | | (33) | | | — | | Contracts realized or settled during the period | | 3 | | | (33) | |
Commodity trading contract additions and changes during the period | Commodity trading contract additions and changes during the period | | 37 | | | 1 | | Commodity trading contract additions and changes during the period | | 9 | | | 37 | |
Fair value of commodity trading net contracts outstanding at March 31 | Fair value of commodity trading net contracts outstanding at March 31 | | $ | (50) | | | $ | (58) | | Fair value of commodity trading net contracts outstanding at March 31 | | $ | (21) | | | $ | (50) | |
At March 31, 2021,2022, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately $14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $13$17 million. At March 31, 2020,2021, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $9$14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $9$13 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 on 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:
| (Millions of Dollars) | (Millions of Dollars) | | Three Months Ended March 31 | | VaR Limit | | Average | | High | | Low | (Millions of Dollars) | | Three Months Ended March 31 | | VaR Limit | | Average | | High | | Low |
2022 | | 2022 | | $ | 1.1 | | | $ | 3.0 | | | $ | 1.0 | | | $ | 1.3 | | | $ | 0.7 | |
2021 | 2021 | | $ | 0.5 | | | $ | 3.0 | | | $ | 2.9 | | | $ | 52.3 | | | $ | 0.5 | | 2021 | | 0.5 | | | 3.0 | | | 2.9 | | | 52.3 | | | 0.5 | |
2020 | | 0.8 | | | 3.0 | | | 0.5 | | | 1.0 | | | 0.3 | | |
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.
Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 11% 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 supply of enriched nuclear material supplied from Russia. Long-term, through 2030, NSP-Minnesota is scheduledUnited States. We will continue to take delivery of approximately 28% ofmonitor the evolving situation in Ukraine and its average enriched nuclear material requirements from these sources. NSP-Minnesota is ableglobal impacts to manage nuclear fuel supply with alternate potential sources. NSP-Minnesota periodically assessesassess if further actions are required to assure a secure supply of enriched nuclear material. NSP-Minnesota is scheduled to take delivery of approximately 30% of its average enriched nuclear material requirements from 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 March 31, 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 $15$12 million and $21$15 million, respectively.
See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ 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 March 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $39 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $28 million. At March 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $34 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $12 million. At March 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $21 million, while a decrease in prices of 10% would have resulted in an immaterial decrease in credit exposure.
Xcel Energy conducts credit reviews for all counterparties and employs credit risk control, 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 March 31, 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 March 31, 2021.2022.
| | |
LIQUIDITY AND CAPITAL RESOURCES |
Cash Flows
Operating Cash Flows
| | | | | | | | |
(Millions of Dollars) | | Three Months Ended March 31 |
Cash provided byused in operating activities — 20202021 | | $ | 669 (136) | |
| | |
Components of change — 20212022 vs. 20202021 | | |
Higher net income | | 6718 | |
Non-cash transactions (a) | | (19)15 | |
Changes in working capital (b) | | 238 (36) | |
Changes in net regulatory and other assets and liabilities | | (1,091)1,279 | |
Cash used inprovided by operating activities — 20212022 | | $ | (136)1,140 | |
(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 $805increased $1,276 million for the three months ended March 31, 20212022 compared with the prior year. DecreaseThe increase was primarily due to the deferral of net natural gas, fuel and purchased energy costs related to Winter Storm Uri.Uri in the first quarter of 2021.
Investing Cash Flows
| | | | | | | | |
(Millions of Dollars) | | Three Months Ended March 31 |
Cash used in investing activities — 20202021 | | $ | (1,606)(1,035) | |
| | |
Components of change — 20212022 vs. 20202021 | | |
Decreased capital expenditures | | 58382 | |
| | |
Other investing activities | | (12)1 | |
Cash used in investing activities — 20212022 | | $ | (1,035)(952) | |
Net cash used in investing activities decreased $571$83 million for the three months ended March 31, 20212022 compared with the prior year. Decreased levels ofThe decrease in capital expenditures was largely due to timing and the purchasecompletion of MEC in January 2020, which was subsequently sold in July 2020.various wind projects.
Financing Cash Flows
| | | | | | | | |
(Millions of Dollars) | | Three Months Ended March 31 |
Cash used in financing activities — 2020 | | $ | 933 | |
| | |
Components of change — 2021 vs. 2020 | | |
Higher debt issuances | | 1,544 | |
Higher repayments of long-term debt | | (400) | |
Higher dividends paid to shareholders | | (19) | |
Other financing activities | | 23 | |
Cash provided by financing activities — 2021 | | $ | 2,081 | |
| | |
Components of change — 2022 vs. 2021 | | |
Lower debt issuances | | (2,723) | |
Lower repayments of long-term debt | | 400 | |
Higher dividends paid to shareholders | | (17) | |
Other financing activities | | (5) | |
Cash used in financing activities — 2022 | | $ | (264) | |
Net cash provided by (used in) financing activities increased $1,148decreased $2,345 million for the three months ended March 31, 20212022 compared with the prior year. IncreaseThe decrease was primarily attributable to proceeds fromthe amount/timing of debt issuances and repayments, partially attributable to deferral of short-termWinter Storm Uri costs in 2021 and long-term debt, partially offset by higher repayments of long-term debt.pending recovery in 2022 and beyond.
See Note 4 to the consolidated financial statements for further information.
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 the revolving credit facility for two additional one-year periods beyond the June 2024 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 April 26, 2021, XcelApril 25, 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 | | | $ | 200 | | | $ | 1,050 | | | $ | 3 | | | $ | 1,053 | | Xcel Energy Inc. | | $ | 1,250 | | | $ | 641 | | | $ | 609 | | | $ | 1 | | | $ | 610 | |
PSCo | PSCo | | 700 | | | 8 | | | 692 | | | 144 | | | 836 | | PSCo | | 700 | | | 133 | | | 567 | | | 3 | | | 570 | |
NSP-Minnesota | NSP-Minnesota | | 500 | | | 10 | | | 490 | | | 518 | | | 1,008 | | NSP-Minnesota | | 500 | | | 11 | | | 489 | | | 3 | | | 492 | |
SPS | SPS | | 500 | | | 2 | | | 498 | | | 43 | | | 541 | | SPS | | 500 | | | 256 | | | 244 | | | 2 | | | 246 | |
NSP-Wisconsin | NSP-Wisconsin | | 150 | | | — | | | 150 | | | 2 | | | 152 | | NSP-Wisconsin | | 150 | | | 50 | | | 100 | | | 1 | | | 101 | |
Total | Total | | $ | 3,100 | | | $ | 220 | | | $ | 2,880 | | | $ | 710 | | | $ | 3,590 | | Total | | $ | 3,100 | | | $ | 1,091 | | | $ | 2,009 | | | $ | 10 | | | $ | 2,019 | |
(a)Credit facilities expire in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
Bilateral Credit Agreement
In April 2021, the2022, 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 March 31, 2021,2022, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreementbilateral credit agreement were as follows:
| (Millions of Dollars) | (Millions of Dollars) | | Limit | | Amount Outstanding | | Available | (Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
NSP-Minnesota | NSP-Minnesota | | $ | 75 | | | $ | 49 | | | $ | 26 | | NSP-Minnesota | | $ | 75 | | | $ | 45 | | | $ | 30 | |
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:
•$1.25 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$500 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 March 31, 2021 | | Year Ended Dec. 31, 2020 | (Amounts in Millions, Except Interest Rates) | | Three Months Ended March 31, 2022 | | Year Ended Dec. 31, 2021 |
Borrowing limit | Borrowing limit | | $ | 4,300 | | | $ | 3,100 | | Borrowing limit | | $ | 3,100 | | | $ | 3,100 | |
Amount outstanding at period end | Amount outstanding at period end | | 1,477 | | | 584 | | Amount outstanding at period end | | 996 | | | 1,005 | |
Average amount outstanding | Average amount outstanding | | 1,129 | | | 1,126 | | Average amount outstanding | | 1,061 | | | 1,399 | |
Maximum amount outstanding | Maximum amount outstanding | | 2,054 | | | 2,080 | | Maximum amount outstanding | | 1,357 | | | 2,054 | |
Weighted average interest rate, computed on a daily basis | Weighted average interest rate, computed on a daily basis | | 0.53 | % | | 1.45 | % | Weighted average interest rate, computed on a daily basis | | 0.42 | % | | 0.57 | % |
Weighted average interest rate at period end | Weighted average interest rate at period end | | 0.73 | | | 0.23 | | Weighted average interest rate at period end | | 0.93 | | | 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.
20212022 Planned Financing Activity — During 2021,2022, Xcel Energy plans to issue approximatapproximately ely $75$75 to $80 million ofof equity through the DRIP and benefit programs.programs. In addition, Xcel Energy Inc.may issue up to $800 million in equity from 2022-2026. Xcel Energy and its utility subsidiaries issued or anticipate issuingplan to issue the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Issuer | | Security | | Amount | | Status | | Tenor | | Coupon |
PSCo | | First Mortgage Bonds | | $ | 750 | million | | Completed | | 10 Year | | 1.875 | % |
SPS | | First Mortgage Bonds | | 250 | million | | Completed | | 29 Year | | 3.15 | |
NSP-Minnesota | | First Mortgage Bonds | | 425 | million | | Completed | | 10 Year | | 2.25 | |
NSP-Minnesota | | First Mortgage Bonds | | 425 | million | | Completed | | 31 Year | | 3.20 | |
NSP-Wisconsin | | First Mortgage Bonds | | 125 | million | | Planned - Q2 | | N/A | | N/A |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Issuer | | Security | | Amount | | Status | | | | |
Xcel Energy | | Unsecured Bonds | | $ | 700 | million | | Planned - Q2 | | | | |
PSCo | | First Mortgage Bonds | | 700 | million | | Planned - Q2 | | | | |
SPS | | First Mortgage Bonds | | 200 | million | | Planned - Q2 | | | | |
NSP-Minnesota | | First Mortgage Bonds | | 500 | million | | Planned - Q2 | | | | |
| | | | | | | | | | |
NSP-Wisconsin | | First Mortgage Bonds | | 100 | million | | Planned - Q3 | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
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’s 20212022 GAAP and ongoing earnings guidance is a range of $2.90$3.10 to $3.00$3.20 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% to 2%.
•Weather-normalized retail firm natural gas sales are projected to be relatively flat.increase ~1%.
•Capital rider revenue is projected to increase $100$0 million to $110$10 million (net of PTCs). The change in the capital rider assumption reflects an increase in the PTC rate, as published by the IRS in April 2022, and will not materially impact earnings as it will be offset by lower tax expense. PTCs are credited to customers through capital riders fuel clause or base rates and results in a reductionreductions to electric margin.other regulatory mechanisms.
•O&M expenses are projected to be relatively flat.increase approximately 1%.
•Depreciation expense is projected to increase approximately $155$285 million to $165$295 million. The change in assumption is a result of new rates going into effect in Colorado and New Mexico for changes in depreciation expense is largely earnings neutrallives and primarily reflects the timing of deferrals andwill be offset by revenue recognition in the Texas rate case.with minimal impact on earnings.
•Property taxes are projected to increase approximately $40 million to $50 million.
•Interest expense (net of AFUDC - debt) is projected to increase $20$80 million to $30$90 million. The assumption change reflects higher interest rates and slightly larger debt issuances.
•AFUDC - equity is projected to decline approximately $40 million to $50 million.be relatively flat.
•ETR is projected to be (7%~(6%) to (8%). The change in the ETR assumption reflects benefitsan increase in the PTC rate, as published by the IRS in April 2022. The impacts 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 20202021 base of $2.78$2.96 per share, which represents the mid-point of the original 2020revised 2021 guidance range of $2.73$2.94 to $2.83$2.98 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 March 31, 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.
PartPART 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. Unless otherwise required by GAAP, legalLegal 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:
The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter endedMarch 31, 2021:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Issuer Purchases of Equity Securities |
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs |
Jan. 1, 2021 - Jan. 31, 2021 | | — | | | $ | — | | | — | | | — | |
Feb. 1, 2021 - Feb. 28, 2021 | | — | | | — | | | — | | | — | |
March 1, 2021 - March 31, 2021 (a) | | 4,399 | | | 58.59 | | | — | | | — | |
| | 4,399 | | | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Issuer Purchases of Equity Securities |
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs |
Jan. 1, 2022 - Jan. 31, 2022 | | — | | | $ | — | | | — | | | — | |
Feb. 1, 2022 - Feb. 28, 2022 | | — | | | — | | | — | | | — | |
March 1, 2022 - March 31, 2022 (a) | | 2,376 | | | 67.33 | | | — | | | — | |
| | 2,376 | | | | | — | | | — | |
(a)Xcel Energy Inc. or one of its agents periodically purchases common shares in open-market transactions in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.
* 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 |
| Supplemental Trust Indenture dated as of March 1, 2021 between Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $425,000,000 aggregate principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425,000,000 aggregate principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052. | NSP-Minnesota 8-K dated March 30, 2021 | 4.01 |
| | PSCo Form 8-K dated March 1, 2021 | 4.01 |
| | Xcel Energy Inc. Form 8-K dated February 18, 2021 | 10.01 |
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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) | | |
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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 |
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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. |
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April 29, 20214/28/2022 | By: | /s/ JEFFREY S. SAVAGE |
| | Jeffrey S. Savage |
| | Senior Vice President, Controller |
| | (Principal Accounting Officer) |
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| | /s/ BRIAN J. VAN ABEL |
| | Brian J. Van Abel |
| | Executive Vice President, Chief Financial Officer |
| | (Duly Authorized Officer and Principal Financial Officer) |