Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See Item 15-1 for an index of financial statements included herein.

See Note 15 to the consolidated financial statements for further information.

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Management Report on Internal Control Over Financial Reporting

The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2021. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2021, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

Xcel Energy Inc.’s independent registered public accounting firm has issued an attestation report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.

/s/ ROBERT C. FRENZEL									/s/ BRIAN J. VAN ABEL
Robert C. Frenzel									Brian J. Van Abel
Chairman, President, Chief Executive Officer and Director									Executive Vice President, Chief Financial Officer
Feb. 23, 2022									Feb. 23, 2022

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Xcel Energy Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements*.*

Critical Audit Matter Description

The Company 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. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.

The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

• We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

• We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural schedules and memorandums, filings made by intervenors, experts’ testimony and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.

• We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 23, 2022
We have served as the Company’s auditor since 2002.

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions, except per share data)

						Year Ended Dec. 31
						2021						2020						2019
Operating revenues
Electric						$	11,205					$	9,802					$	9,575
Natural gas						2,132						1,636						1,868
Other						94						88						86
Total operating revenues						13,431						11,526						11,529
Operating expenses
Electric fuel and purchased power						4,733						3,512						3,510
Cost of natural gas sold and transported						1,081						689						918
Cost of sales — other						38						37						40
Operating and maintenance expenses						2,321						2,324						2,338
Conservation and demand side management expenses						304						288						285
Depreciation and amortization						2,121						1,948						1,765
Taxes (other than income taxes)						630						612						569
Total operating expenses						11,228						9,410						9,425
Operating income						2,203						2,116						2,104
Other income (expense), net						5						(6)						16
Earnings from equity method investments						62						40						39
Allowance for funds used during construction — equity						73						115						77
Interest charges and financing costs
Interest charges — includes other financing costs of $29, $28 and $26, respectively						842						840						773
Allowance for funds used during construction — debt						(26)						(42)						(37)
Total interest charges and financing costs						816						798						736
Income before income taxes						1,527						1,467						1,500
Income tax (benefit) expense						(70)						(6)						128
Net income						$	1,597					$	1,473					$	1,372
Weighted average common shares outstanding:
Basic						539						527						519
Diluted						540						528						520
Earnings per average common share:
Basic						$	2.96					$	2.79					$	2.64
Diluted						2.96						2.79						2.64
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

						Year Ended Dec. 31
						2021						2020						2019
Net income						$	1,597					$	1,473					$	1,372
Other comprehensive income (loss)
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $—, $(2) and $—, respectively						—						(5)						—
Reclassification of losses to net income, net of tax of $3, $3 and $1, respectively						8						10						3
Derivative instruments:
Net fair value increase (decrease), net of tax of $1, $(3) and $(8), respectively						4						(10)						(23)
Reclassification of losses to net income, net of tax of $2, $2 and $1, respectively						6						5						3
Total other comprehensive income (loss)						18						—						(17)
Total comprehensive income						$	1,615					$	1,473					$	1,355
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)

			Year Ended Dec. 31
			2021						2020						2019
Operating activities
Net income			$	1,597					$	1,473					$	1,372
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization			2,143						1,959						1,785
Nuclear fuel amortization			114						123						119
Deferred income taxes			(79)						(8)						143
Allowance for equity funds used during construction			(73)						(115)						(77)
Earnings from equity method investments			(62)						(40)						(39)
Dividends from equity method investments			42						42						40
Provision for bad debts			60						60						42
Share-based compensation expense			31						73						58
Net realized and unrealized hedging and derivative transactions			(57)						(27)						45
Changes in operating assets and liabilities:
Accounts receivable			(164)						(154)						(20)
Accrued unbilled revenues			(149)						(3)						42
Inventories			(126)						(80)						(84)
Other current assets			(34)						(45)						25
Accounts payable			138						(33)						(12)
Net regulatory assets and liabilities			(973)						(144)						(66)
Other current liabilities			(1)						29						(15)
Pension and other employee benefit obligations			(135)						(125)						(135)
Other, net			(83)						(137)						40
Net cash provided by operating activities			2,189						2,848						3,263
Investing activities
Capital/construction expenditures			(4,244)						(5,369)						(4,225)
Sale of MEC			—						684						—
Purchase of investment securities			(757)						(1,398)						(995)
Proceeds from the sale of investment securities			743						1,378						975
Other, net			(29)						(35)						(98)
Net cash used in investing activities			(4,287)						(4,740)						(4,343)
Financing activities
Proceeds from (repayments of) short-term borrowings, net			421						(11)						(443)
Proceeds from issuances of long-term debt			2,710						2,940						2,920
Repayments of long-term debt, including reacquisition premiums			(417)						(1,001)						(949)
Proceeds from issuance of common stock			366						727						458
Dividends paid			(935)						(856)						(791)
Other, net			(10)						(26)						(14)
Net cash provided by financing activities			2,135						1,773						1,181
Net change in cash and cash equivalents			37						(119)						101
Cash, cash equivalents and restricted cash at beginning of period			129						248						147
Cash, cash equivalents and restricted cash at end of period			$	166					$	129					$	248
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)			$	(788)					$	(758)					$	(698)
Cash (paid) received for income taxes, net			(4)						12						53
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions			$	501					$	400					$	421
Inventory transfers to property, plant and equipment			87						275						88
Operating lease right-of-use assets			8						369						1,843
Allowance for equity funds used during construction			73						115						77
Issuance of common stock for reinvested dividends and/or equity awards			60						67						63
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in millions, except share and per share)

						Dec. 31
						2021						2020
Assets
Current assets
Cash and cash equivalents						$	166					$	129
Accounts receivable, net						1,018						916
Accrued unbilled revenues						862						714
Inventories						631						535
Regulatory assets						1,106						640
Derivative instruments						123						49
Prepaid taxes						44						42
Prepayments and other						289						250
Total current assets						4,239						3,275
Property, plant and equipment, net						45,457						42,950
Other assets
Nuclear decommissioning fund and other investments						3,628						3,096
Regulatory assets						2,738						2,737
Derivative instruments						67						30
Operating lease right-of-use assets						1,291						1,490
Other						431						379
Total other assets						8,155						7,732
Total assets						$	57,851					$	53,957
Liabilities and Equity
Current liabilities
Current portion of long-term debt						$	601					$	421
Short-term debt						1,005						584
Accounts payable						1,409						1,237
Regulatory liabilities						271						311
Taxes accrued						569						578
Accrued interest						209						203
Dividends payable						249						231
Derivative instruments						69						53
Operating lease liabilities						205						214
Other						459						407
Total current liabilities						5,046						4,239
Deferred credits and other liabilities
Deferred income taxes						4,894						4,746
Deferred investment tax credits						53						45
Regulatory liabilities						5,405						5,302
Asset retirement obligations						3,151						2,884
Derivative instruments						105						131
Customer advances						196						197
Pension and employee benefit obligations						306						666
Operating lease liabilities						1,146						1,344
Other						158						183
Total deferred credits and other liabilities						15,414						15,498
Commitments and contingencies
Capitalization
Long-term debt						21,779						19,645
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 544,025,269 and 537,438,394 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively						1,360						1,344
Additional paid in capital						7,803						7,404
Retained earnings						6,572						5,968
Accumulated other comprehensive loss						(123)						(141)
Total common stockholders’ equity						15,612						14,575
Total liabilities and equity						$	57,851					$	53,957
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

(amounts in millions, except per share data; shares in actual amounts)

			Common Stock Issued																		Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Stockholders’ Equity
			Shares						Par Value						Additional Paid In Capital
Balance at Dec. 31, 2018			514,036,787						$	1,285					$	6,168					$	4,893					$	(124)					$	12,222
Net income																					1,372												1,372
Other comprehensive income																											(17)						(17)
Dividends declared on common stock ($1.62 per share)																					(846)												(846)
Issuances of common stock			10,507,943						26						468																		494
Repurchases of common stock			(5,730)						—						—																		—
Share-based compensation															20						(6)												14
Balance at Dec. 31, 2019			524,539,000						$	1,311					$	6,656					$	5,413					$	(141)					$	13,239
Net Income																					1,473												1,473
Dividends declared on common stock ($1.72 per share)																					(909)												(909)
Issuances of common stock			12,953,869						33						731																		764
Repurchase of common stock			(54,475)						—						(4)																		(4)
Share-based compensation															21						(7)												14
Adoption of ASC Topic 326																					(2)												(2)
Balance at Dec. 31, 2020			537,438,394						$	1,344					$	7,404					$	5,968					$	(141)					$	14,575
Net income																					1,597												1,597
Other comprehensive income																											18						18
Dividends declared on common stock ($1.83 per share)																					(989)												(989)
Issuances of common stock			6,586,875						16						387																		403
Share-based compensation															12						(4)												8
Balance at Dec. 31, 2021			544,025,269						$	1,360					$	7,803					$	6,572					$	(123)					$	15,612
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.

Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.

Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings. Eloigne invests in rental housing projects that qualify for low-income housing tax credits. Capital Services procures equipment for construction of renewable generation facilities at other subsidiaries. Venture Holdings invests in limited partnerships, including EIP funds with portfolios of investments in energy technology companies. Nicollet Project Holdings invests in nonregulated assets such as the MEC generating facility (through July 2020) and Minnesota community solar gardens. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., Xcel Energy Transmission Holding Company, LLC, Nicollet Holdings Company, LLC, Xcel Energy Nuclear Services Holdings, LLC and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy.

Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. Xcel Energy uses the equity method of accounting for its investments in EIP funds and WYCO.

Xcel Energy has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.

Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

Xcel Energy has evaluated events occurring after Dec. 31, 2021 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates — Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations.

Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.

Regulatory Accounting — Xcel Energy Inc.’s regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

• Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities.

Xcel Energy uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which would be refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.

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Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

Xcel Energy reports interest and penalties related to income taxes within other (expense) income or interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Xcel Energy records depreciation expense using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs of Xcel Energy’s utility subsidiaries are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5% for 2021, 3.4% for 2020 and 3.3% for 2019.

See Note 3 for further information.

AROs — Xcel Energy accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 12 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval.

NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Notes 10 and 12 for further information.

Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 11 for further information.

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Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 12 for further information.

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.

Xcel Energy does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. Xcel Energy presents its revenues net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2021 and 2020, the allowance for bad debts was $106 million and $79 million, respectively.

Inventory — Inventory is recorded at average cost and consisted of the following:

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
Inventories
Materials and supplies						$	289					$	275
Fuel						182						176
Natural gas						160						84
Total inventories						$	631					$	535

Equity Method Investments — The equity method of accounting is used for investments in WYCO and EIP funds, which results in Xcel Energy’s recognition of its share of these investees’ GAAP pretax earnings, based on Xcel Energy’s proportional ownership interest. For investments in EIP funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies.

Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.

Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.

For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.

See Notes 10 and 11 for further information.

Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 10 for further information.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.

See Note 10 for further information.

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Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate or from other instances where the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs recognized on the consolidated balance sheets, however these assets are classified as regulatory assets if amounts are recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.

2. Accounting Pronouncements

Recently Adopted

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 32**6 (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, adoption of ASC Topic 326 did not have a significant impact on Xcel Energy’s consolidated financial statements.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
Property, plant and equipment, net
Electric plant						$	48,680					$	47,104
Natural gas plant						7,758						7,135
Common and other property						2,602						2,503
Plant to be retired (a)						1,200						677
CWIP						1,969						1,877
Total property, plant and equipment						62,209						59,296
Less accumulated depreciation						(17,060)						(16,657)
Nuclear fuel						3,081						2,970
Less accumulated amortization						(2,773)						(2,659)
Property, plant and equipment, net						$	45,457					$	42,950

(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 3 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.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2021:

(Millions of Dollars, Except Percent Owned)						Plant in Service						Accumulated Depreciation												Percent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3						$	620					$	451											59		%
Sherco common facilities						178						108												80
Sherco substation						5						4												59
Electric transmission:
Grand Meadow						11						3												50
Huntley Wilmarth						48						1												50
CapX2020						952						127												51
Total NSP-Minnesota (a)						$	1,814					$	694

(a)Projects additionally include $7 million in CWIP.

(Millions of Dollars, Except Percent Owned)						Plant in Service						Accumulated Depreciation												Percent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI						$	177					$	15											37		%
CapX2020						169						28												80
Total NSP-Wisconsin (a)						$	346					$	43

(a)Projects additionally include $2 million in CWIP.

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(Millions of Dollars, Except Percent Owned)						Plant in Service						Accumulated Depreciation												Percent Owned
PSCo
Electric generation:
Hayden Unit 1						$	156					$	99											76		%
Hayden Unit 2						151						78												37
Hayden common facilities						42						27												53
Craig Units 1 and 2						81						48												10
Craig common facilities						39						25												7
Comanche Unit 3						917						154												67
Comanche common facilities						28						2												82
Electric transmission:
Transmission and other facilities						182						63												Various
Gas transmission:
Rifle, CO to Avon, CO						22						8												60
Gas transmission compressor						8						2												50
Total PSCo (a)						$	1,626					$	506

(a)Projects additionally include $4 million in CWIP.

Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

4. Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:

(Millions of Dollars)						See Note(s)						Remaining Amortization Period						Dec. 31, 2021												Dec. 31, 2020
Regulatory Assets																		Current						Noncurrent						Current						Noncurrent
Pension and retiree medical obligations						11						Various						$	77					$	944					$	82					$	1,268
Deferred natural gas, electric, steam energy/fuel costs												One to five years						504						543						14						18
Recoverable deferred taxes on AFUDC												Plant lives						—						289						—						283
Excess deferred taxes — TCJA						7						Various						14						219						16						229
Depreciation differences												One to 10 years						16						173						16						154
Environmental remediation costs						1, 12						Various						14						92						16						113
Texas revenue surcharges												One to two years						20						64						54						17
Sales true-up and revenue decoupling												One to two years						33						56						101						28
Benson biomass PPA termination and asset purchase												Eight years						10						55						10						65
Renewable resources and environmental initiatives												One to two years						170						48						129						12
PI extended power uprate												13 years						4						46						3						49
Purchased power contract costs												Term of related contract						9						45						7						54
Conservation programs (a)						1						One to two years						21						35						26						36
Losses on reacquired debt												Term of related debt						3						35						4						38
Contract valuation adjustments (b)						1, 10						Term of related contract						22						34						23						48
State commission adjustments												Plant lives						1						32						1						32
Laurentian biomass PPA termination												Two years						18						18						18						36
Nuclear refueling outage costs						1						One to two years						37						16						28						10
Property tax												Various						16						16						16						21
Gas pipeline inspection and remediation costs												One to two years						33						12						26						9
Net AROs (c)						1, 12						Various						—						(112)						—						139
Other												Various						84						78						50						78
Total regulatory assets																		$	1,106					$	2,738					$	640					$	2,737

(a)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(b)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

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Components of regulatory liabilities:

(Millions of Dollars)						See Note(s)						Remaining Amortization Period						Dec. 31, 2021												Dec. 31, 2020
Regulatory Liabilities																		Current						Noncurrent						Current						Noncurrent
Deferred income tax adjustments and TCJA refunds (a)						7						Various						$	26					$	3,230					$	20					$	3,368
Plant removal costs						1, 12						Various						—						1,655						—						1,520
Effects of regulation on employee benefit costs (b)												Various						—						235						—						221
Renewable resources and environmental initiatives												Various						1						101						5						59
ITC deferrals						1						Various						—						53						—						51
Revenue decoupling												One to two years						9						41						10						41
Contract valuation adjustments (c)						1, 10						One to three years						56						1						19						—
Deferred natural gas, electric, steam energy/fuel costs												Less than one year						50						—						84						—
Conservation programs (d)						1						Less than one year						42						—						49						—
DOE settlement												Less than one year						14						14						23						—
Other												Various						73						75						101						42
Total regulatory liabilities (e)																		$	271					$	5,405					$	311					$	5,302

(a)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.

(b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.

(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(d)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(e)Revenue subject to refund of $17 million for both 2021 and 2020 is included in other current liabilities.

At Dec. 31, 2021 and 2020, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, regulatory assets included $1,718 million and $812 million at Dec. 31, 2021 and 2020, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs (including those related to Winter Storm Uri), various renewable resources and certain environmental initiatives.

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

Short-Term Debt — Xcel Energy meets its 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:

(Millions of Dollars, Except Interest Rates)						Three Months Ended Dec. 31, 2021						Year Ended Dec. 31
						2021						2020						2019
Borrowing limit						$	3,100					$	3,100					$	3,100					$	3,600
Amount outstanding at period end						1,005						1,005						584						595
Average amount outstanding						1,200						1,399						1,126						1,115
Maximum amount outstanding						1,774						2,054						2,080						1,780
Weighted average interest rate, computed on a daily basis						0.54		%				0.57		%				1.45		%				2.72		%
Weighted average interest rate at period end						0.31						0.31						0.23						2.34

Term Loan Agreements — In the fourth quarter of 2021, Xcel Energy repaid its $1.2 billion 364-Day Term Loan Agreement.

Bilateral Credit Agreement — In April 2021, 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 Dec. 31, 2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million the Bilateral Credit Agreement.

Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2021 and 2020, there were $19 million and $20 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.

Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. 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.

Terms of Credit Agreements — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements is $3.1 billion, with a swingline subfacility for Xcel Energy up to $75 million. The amended credit agreements mature in June 2024.

Features of the credit facilities:

						Debt-to-Total Capitalization Ratio (a)												Amount Facility May Be Increased (millions of dollars)						Additional Periods for Which a One-Year Extension May Be Requested (b)
						2021						2020
Xcel Energy Inc. (c)						60		%				59		%				$	250					2
NSP-Wisconsin						49						46						N/A						1
NSP-Minnesota						47						47						100						2
SPS						47						48						50						2
PSCo						44						44						100						2

(a) Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b) All extension requests are subject to majority bank group approval.

(c) The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.

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If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2021, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants.

Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2021:

(Millions of Dollars)						Credit Facility (a)						Drawn (b)						Available
Xcel Energy Inc.						$	1,250					$	638					$	612
PSCo						700						155						545
NSP-Minnesota						500						9						491
SPS						500						139						361
NSP-Wisconsin						150						83						67
Total						$	3,100					$	1,024					$	2,076

(a)These credit facilities mature in June 2024.

(b)Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2021 and 2020.

Long-Term Borrowings and Other Financing Instruments

Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):

Xcel Energy Inc.
Financing Instrument						Interest Rate						Maturity Date						2021						2020
Unsecured senior notes						2.40		%				March 15, 2021						$	—					$	400
Unsecured senior notes (b)						0.50						Oct. 15, 2023						500						500
Unsecured senior notes						3.30						June 1, 2025						250						250
Unsecured senior notes						3.30						June 1, 2025						350						350
Unsecured senior notes						3.35						Dec. 1, 2026						500						500
Unsecured senior notes (a)						1.75						March 15,2027						500						—
Unsecured senior notes						4.00						June 15, 2028						130						130
Unsecured senior notes						4.00						June 15, 2028						500						500
Unsecured senior notes						2.60						Dec. 1, 2029						500						500
Unsecured senior notes (b)						3.40						June 1, 2030						600						600
Unsecured senior notes (a)						2.35						Nov. 15, 2031						300						—
Unsecured senior notes						6.50						July 1, 2036						300						300
Unsecured senior notes						4.80						Sep. 15, 2041						250						250
Unsecured senior notes						3.50						Dec. 1, 2049						500						500
Unamortized discount																		(8)						(7)
Unamortized debt issuance cost																		(33)						(32)
Current maturities																		—						(400)
Total long-term debt																		$	5,139					$	4,341

(a)2021 financing.

(b)2020 financing.

NSP-Minnesota
Financing Instrument						Interest Rate						Maturity Date						2021						2020
First mortgage bonds						2.15		%				Aug. 15, 2022						$	300					$	300
First mortgage bonds						2.60						May 15, 2023						400						400
First mortgage bonds						7.125						July 1, 2025						250						250
First mortgage bonds						6.50						March 1, 2028						150						150
First mortgage bonds (a)						2.25						April 1, 2031						425						—
First mortgage bonds						5.25						July 15, 2035						250						250
First mortgage bonds						6.25						June 1, 2036						400						400
First mortgage bonds						6.20						July 1, 2037						350						350
First mortgage bonds						5.35						Nov. 1, 2039						300						300
First mortgage bonds						4.85						Aug. 15, 2040						250						250
First mortgage bonds						3.40						Aug. 15, 2042						500						500
First mortgage bonds						4.125						May 15, 2044						300						300
First mortgage bonds						4.00						Aug. 15, 2045						300						300
First mortgage bonds						3.60						May 15, 2046						350						350
First mortgage bonds						3.60						Sep. 15, 2047						600						600
First mortgage bonds						2.90						March 1, 2050						600						600
First mortgage bonds (b)						2.60						June 1, 2051						700						700
First mortgage bonds (a)						3.20						April 1,2052						425						—
Other long-term debt																		3						—
Unamortized discount																		(44)						(42)
Unamortized debt issuance cost																		(62)						(54)
Current maturities																		(300)						—
Total long-term debt																		$	6,447					$	5,904

(a)2021 financing.

(b)2020 financing.

NSP-Wisconsin
Financing Instrument						Interest Rate						Maturity Date						2021						2020
City of La Crosse resource recovery bond						6.00		%				Nov. 1, 2021						$	—					$	19
First mortgage bonds						3.30						June 15, 2024						100						100
First mortgage bonds						3.30						June 15, 2024						100						100
First mortgage bonds						6.375						Sept. 1, 2038						200						200
First mortgage bonds						3.70						Oct. 1, 2042						100						100
First mortgage bonds						3.75						Dec. 1, 2047						100						100
First mortgage bonds						4.20						Sept. 1, 2048						200						200
First mortgage bonds (b)						3.05						May 1, 2051						100						100
First mortgage bonds (a)						2.82						May 1, 2051						100						—
Other long-term debt																		1						—
Unamortized discount																		(4)						(4)
Unamortized debt issuance cost																		(10)						(9)
Current maturities																		—						(19)
Total long-term debt																		$	987					$	887

(a)2021 financing.

(b)2020 financing.

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PSCo
Financing Instrument						Interest Rate						Maturity Date						2021						2020
First mortgage bonds						2.25		%				Sept. 15, 2022						$	300					$	300
First mortgage bonds						2.50						March 15, 2023						250						250
First mortgage bonds						2.90						May 15, 2025						250						250
First mortgage bonds						3.70						June 15, 2028						350						350
First mortgage bonds (b)						1.90						Jan. 15, 2031						375						375
First mortgage bonds (a)						1.875						June 15, 2031						750						—
First mortgage bonds						6.25						Sept. 1, 2037						350						350
First mortgage bonds						6.50						Aug. 1, 2038						300						300
First mortgage bonds						4.75						Aug. 15, 2041						250						250
First mortgage bonds						3.60						Sept. 15, 2042						500						500
First mortgage bonds						3.95						March 15, 2043						250						250
First mortgage bonds						4.30						March 15, 2044						300						300
First mortgage bonds						3.55						June 15, 2046						250						250
First mortgage bonds						3.80						June 15, 2047						400						400
First mortgage bonds						4.10						June 15, 2048						350						350
First mortgage bonds						4.05						Sept. 15, 2049						400						400
First mortgage bonds						3.20						March 1, 2050						550						550
First mortgage bonds (b)						2.70						Jan. 15, 2051						375						375
Unamortized discount																		(33)						(30)
Unamortized debt issuance cost																		(50)						(46)
Current maturities																		(300)						—
Total long-term debt																		$	6,167					$	5,724

(a)2021 financing.

(b)2020 financing.

SPS
Financing Instrument						Interest Rate						Maturity Date						2021						2020
First mortgage bonds						3.30		%				June 15, 2024						$	150					$	150
First mortgage bonds						3.30						June 15, 2024						200						200
Unsecured senior notes						6.00						Oct. 1, 2033						100						100
Unsecured senior notes						6.00						Oct. 1, 2036						250						250
First mortgage bonds						4.50						Aug. 15, 2041						200						200
First mortgage bonds						4.50						Aug. 15, 2041						100						100
First mortgage bonds						4.50						Aug. 15, 2041						100						100
First mortgage bonds						3.40						Aug. 15, 2046						300						300
First mortgage bonds						3.70						Aug. 15, 2047						450						450
First mortgage bonds						4.40						Nov. 15, 2048						300						300
First mortgage bonds						3.75						June 15, 2049						300						300
First mortgage bonds (b)						3.15						May 1, 2050						350						350
First mortgage bonds (a)						3.15						May 1, 2050						250						—
Unamortized discount																		(9)						(10)
Unamortized debt issuance cost																		(28)						(26)
Total long-term debt																		$	3,013					$	2,764

(a)2020 financing re-opened in 2021.

(b)2020 financing.

Other Subsidiaries
Financing Instrument						Interest Rate						Maturity Date						2021						2020
Various Eloigne affordable housing project notes						0.00% - 6.50%						2022 — 2055						$	27					$	27
Current maturities																		(1)						(2)
Total long-term debt																		$	26					$	25

Maturities of long-term debt:

(Millions of Dollars)
2022						$	601
2023						1,150
2024						552
2025						1,102
2026						501

Deferred Financing Costs — Deferred financing costs of approximately $184 million and $167 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2021 and 2020, respectively.

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. As of Dec. 31, 2021, Xcel Energy Inc. had issued 5.33 million shares of common stock with net proceeds of $347 million through the ATM program.

Capital Stock — Preferred stock authorized/outstanding:

						Preferred Stock Authorized (Shares)						Par Value of Preferred Stock						Preferred Stock Outstanding (Shares) 2021 and 2020
Xcel Energy Inc.						7,000,000						$	100					—
PSCo						10,000,000						0.01						—
SPS						10,000,000						1.00						—

Xcel Energy Inc. had the following common stock authorized/outstanding:

Common Stock Authorized (Shares)						Par Value of Common Stock						Common Stock Outstanding (Shares) as of Dec. 31, 2021						Common Stock Outstanding (Shares) as of Dec. 31, 2020
1,000,000,000						$	2.50					544,025,269						537,438,394

Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements.

State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2021:

						Equity to Total Capitalization Ratio Required Range												Equity to Total Capitalization Ratio Actual
						Low						High						2021
NSP-Minnesota						47.2		%				57.6		%				52.9		%
NSP-Wisconsin						52.5						N/A						52.8
SPS (a)						45.0						55.0						54.5

(a) Excludes short-term debt.

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(Amounts in Millions)						Unrestricted Retained Earnings						Total Capitalization						Limit on Total Capitalization
NSP-Minnesota						$	1,558					$	14,321					$	15,332
NSP-Wisconsin (a)						11						2,091						N/A
SPS (b)						513						6,615						N/A

(a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.

(b) May not pay a dividend that would cause a loss of its investment grade bond rating.

Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.

Amounts authorized to issue as of Dec. 31, 2021:

(Millions of Dollars)						Long-Term Debt						Short-Term Debt
NSP-Minnesota						52.8% of total capitalization			(a)			$	2,300		(a)
NSP-Wisconsin						$	150					150
SPS						—						600
PSCo						700			(b)			800

(a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.

(b) PSCo filed for additional long-term debt authorization in December 2021.

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:

						Year Ended Dec. 31, 2021
(Millions of Dollars)						Electric						Natural Gas						All Other						Total
Major revenue types
Revenue from contracts with customers:
Residential						$	3,194					$	1,222					$	45					$	4,461
C&I						5,050						640						30						5,720
Other						127						—						7						134
Total retail						8,371						1,862						82						10,315
Wholesale						1,540						—						—						1,540
Transmission						604						—						—						604
Other						61						148						—						209
Total revenue from contracts with customers						10,576						2,010						82						12,668
Alternative revenue and other						629						122						12						763
Total revenues						$	11,205					$	2,132					$	94					$	13,431

						Year Ended Dec. 31, 2020
(Millions of Dollars)						Electric						Natural Gas						All Other						Total
Major revenue types
Revenue from contracts with customers:
Residential						$	3,066					$	975					$	42					$	4,083
C&I						4,596						462						27						5,085
Other						125						—						6						131
Total retail						7,787						1,437						75						9,299
Wholesale						759						—						—						759
Transmission						579						—						—						579
Other						73						137						—						210
Total revenue from contracts with customers						9,198						1,574						75						10,847
Alternative revenue and other						604						62						13						679
Total revenues						$	9,802					$	1,636					$	88					$	11,526

						Year Ended Dec. 31, 2019
(Millions of Dollars)						Electric						Natural Gas						All Other						Total
Major revenue types
Revenue from contracts with customers:
Residential						$	2,877					$	1,127					$	41					$	4,045
C&I						4,844						567						29						5,440
Other						130						—						4						134
Total retail						7,851						1,694						74						9,619
Wholesale						737						—						—						737
Transmission						507						—						—						507
Other						49						120						—						169
Total revenue from contracts with customers						9,144						1,814						74						11,032
Alternative revenue and other						431						54						12						497
Total revenues						$	9,575					$	1,868					$	86					$	11,529

7. Income Taxes

Federal Loss Carryback Claims - In 2020, Xcel Energy identified certain expense related to tax years 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020.

Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:

Tax Year(s)						Expiration
2014 - 2016						December 2022
2018						September 2022

Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional 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.

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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 Dec. 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						2014
Minnesota						2014
Texas						2016
Wisconsin						2016

• In April 2021, Texas began an audit of tax years 2016-2019. As of Dec. 31, 2021, no material adjustments have been proposed.

• In March 2021, Wisconsin began an audit of tax years 2016 - 2019. As of Dec. 31, 2021, no material adjustments have been proposed.

• In July 2020, Minnesota began an audit of tax years 2015 - 2018. As of Dec. 31, 2021, no material adjustments have been proposed.

• No other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2021.

Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

Unrecognized tax benefits - permanent vs. temporary:

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions						$	47					$	41
Unrecognized tax benefit — Temporary tax positions						11						11
Total unrecognized tax benefit						$	58					$	52

Changes in unrecognized tax benefits:

(Millions of Dollars)						2021						2020						2019
Balance at Jan. 1						$	52					$	44					$	37
Additions based on tax positions related to the current year						5						9						10
Reductions based on tax positions related to the current year						—						(2)						(4)
Additions for tax positions of prior years						2						35						1
Reductions for tax positions of prior years						(1)						(34)						—
Balance at Dec. 31						$	58					$	52					$	44

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
NOL and tax credit carryforwards						$	(36)					$	(31)

As the IRS progresses its review of the tax loss carryback claims and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $28 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)						2021						2020						2019
Payable for interest related to unrecognized tax benefits at Jan. 1						$	(3)					$	—					$	—
Interest expense related to unrecognized tax benefits						—						(3)						—
Payable for interest related to unrecognized tax benefits at Dec. 31						$	(3)					$	(3)					$	—

No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2021, 2020 or 2019.

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31:

(Millions of Dollars)						2021						2020
Federal NOL carryforward						$	765					$	—
Federal tax credit carryforwards						1,172						791
State NOL carryforwards						1,648						839
Valuation allowances for state NOL carryforwards						(3)						(4)
State tax credit carryforwards, net of federal detriment (a)						89						89
Valuation allowances for state credit carryforwards, net of federal benefit (b)						(64)						(64)

(a)State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2021 and 2020.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million as of Dec. 31, 2021 and 2020.

Federal carryforward periods expire between 2031 and 2041 and state carryforward periods expire starting 2022.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

						2021						2020						2019
Federal statutory rate						21.0		%				21.0		%				21.0		%
State income tax on pretax income, net of federal tax effect						5.0						4.9						4.9
(Decreases) increases in tax from:
Wind PTCs						(23.4)						(15.7)						(9.4)
Plant regulatory differences (a)						(6.2)						(7.6)						(5.8)
Other tax credits, net NOL & tax credit allowances						(1.1)						(1.2)						(1.7)
NOL Carryback						—						(0.9)						—
Change in unrecognized tax benefits						0.4						0.5						0.5
Other, net						(0.3)						(1.4)						(1.0)
Effective income tax rate						(4.6)		%				(0.4)		%				8.5		%

(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 and additional prepaid pension asset amortization.

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Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)						2021						2020						2019
Current federal tax expense (benefit)						$	15					$	(13)					$	(16)
Current state tax (benefit) expense						(2)						2						4
Current change in unrecognized tax expense						1						18						2
Deferred federal tax (benefit) expense						(183)						(89)						55
Deferred state tax expense						99						91						83
Deferred change in unrecognized tax expense (benefit)						5						(10)						5
Deferred ITCs						(5)						(5)						(5)
Total income tax (benefit) expense						$	(70)					$	(6)					$	128

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)						2021						2020						2019
Deferred tax expense excluding items below						$	148					$	237					$	344
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities						(221)						(247)						(206)
Tax (benefit) expense allocated to other comprehensive income, adoption of ASC Topic 326, and other						(6)						2						5
Deferred tax (benefit) expense						$	(79)					$	(8)					$	143

Components of net deferred tax liability as of Dec. 31:

(Millions of Dollars)						2021						2020 (a)
Deferred tax liabilities:
Differences between book and tax bases of property						$	6,231					$	5,810
Operating lease assets						351						400
Regulatory assets						598						603
Deferred fuel costs						262						(6)
Pension expense						175						176
Other						93						74
Total deferred tax liabilities						$	7,710					$	7,057
Deferred tax assets:
Regulatory liabilities						$	780					$	806
Operating lease liabilities						351						400
Tax credit carryforward						1,261						880
NOL carryforward						247						37
NOL and tax credit valuation allowances						(64)						(64)
Other employee benefits						119						141
Deferred ITCs						15						13
Other						107						98
Total deferred tax assets						$	2,816					$	2,311
Net deferred tax liability						$	4,894					$	4,746

(a) Prior periods have been reclassified to conform to current year presentation.

8. Share-Based Compensation

Incentive Plan Including Share-Based Compensation — Xcel Energy has an incentive plan which includes share-based payment elements, the Amended and Restated 2015 Omnibus Incentive Plan with 7.0 million equity shares authorized.

Restricted Stock — The Amended and Restated 2015 Omnibus Incentive Plan allows certain employees to elect to receive shares of common or restricted stock. Restricted stock is treated as an equity award and vests and settles in equal annual installments over a three-year period. Restricted stock has a fair value equal to the market trading price of Xcel Energy stock at the grant date.

Shares of restricted stock granted at Dec. 31:

(Shares in Thousands)						2021						2020						2019
Granted shares						2						1						13
Grant date fair value						$	61.54					$	70.26					$	53.46

Changes in nonvested restricted stock:

(Shares in Thousands)						Shares						Weighted Average Grant Date Fair Value
Nonvested restricted stock at Jan. 1, 2021						15						$	56.68
Granted						2						61.54
Forfeited						—						70.26
Vested						(9)						49.71
Dividend equivalents						—						66.73
Nonvested restricted stock at Dec. 31, 2021						8						67.26

Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the Amended and Restated 2015 Omnibus Incentive Plan, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met.

Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. A total of 0.2 million, 0.2 million, and 0.3 million time-based equity shares subject only to service conditions were granted annually in 2021, 2020 and 2019, respectively.

The performance conditions for a portion of the awards granted from 2019 to 2021 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled or forfeited after three years, with payouts ranging from zero to 200% depending on achievement.

Equity award units granted to employees (excluding restricted stock):

(Units in Thousands)						2021						2020						2019
Granted units						421						411						483
Weighted average grant date fair value						$	66.03					$	62.92					$	49.67

Equity awards vested:

(Units in Thousands, Fair Value in Millions)						2021						2020						2019
Vested Units						392						442						464
Total Fair Value						$	27					$	29					$	29

Changes in the nonvested portion of equity award units:

(Units in Thousands)						Units						Weighted Average Grant Date Fair Value
Nonvested Units at Jan. 1, 2021						780						$	55.68
Granted						421						66.03
Forfeited						(146)						61.76
Vested						(392)						48.91
Dividend equivalents						32						58.00
Nonvested Units at Dec. 31, 2021						695						64.59

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Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to one share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their cash fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service.

Stock equivalent units granted:

(Units in Thousands)						2021						2020						2019
Granted units						31						33						29
Weighted average grant date fair value						$	68.15					$	61.61					$	58.44

Changes in stock equivalent units:

(Units in Thousands)						Units						Weighted Average Grant Date Fair Value
Stock equivalent units at Jan. 1, 2021						630						$	36.28
Granted						31						68.15
Units distributed						(73)						31.47
Dividend equivalents						16						66.98
Stock equivalent units at Dec. 31, 2021						604						39.27

TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Amended and Restated 2015 Omnibus Incentive Plan. This plan allows Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a three-year period. Xcel Energy Inc.’s TSR is compared to a peer group of other utility companies. Potential payouts of the awards range from zero to 200%.

TSR liability awards granted:

(In Thousands)						2021						2020						2019
Awards granted						221						212						225

TSR liability awards settled:

(Units In Thousands, Settlement Amount in Millions)						2021						2020						2019
Awards settled						446						476						466
Settlement amount (cash, common stock and deferred amounts)						$	27					$	33					$	25

TSR liability awards of $22 million were settled in cash in 2021.

Share-Based Compensation Expense — Other than for restricted stock, vesting of employee equity awards is typically predicated on the achievement of a TSR or environmental measures target. Additionally, approximately 0.2 million, 0.2 million, and 0.3 million of equity award units were granted in 2021, 2020, and 2019, respectively, with vesting subject only to service conditions of three years.

Generally, these instruments are considered to be equity awards as the award settlement determination (shares or cash) is made by Xcel Energy, not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement.

Grant date fair value of equity awards is expensed over the service period. TSR liability awards have been historically settled partially in cash, and do not qualify as equity awards, but rather are accounted for as liabilities. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the shares on the date the award is settled.

Compensation costs related to share-based awards:

(Millions of Dollars)						2021						2020						2019
Compensation cost for share-based awards (a)						$	31					$	73					$	58
Tax benefit recognized in income						8						19						15

(a)Compensation costs for share-based payments are included in O&M expense.

There was approximately $28 million in 2021 and $51 million in 2020 of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the unrecognized amount over a weighted average period of 1.6 years.

9. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the 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 forward equity agreements and certain equity awards in share-based compensation arrangements. Common stock equivalents include commitments to issue common stock related to time-based equity compensation awards.

Stock equivalent units granted to Xcel Energy’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. Restricted stock issued to employees under the Executive Annual Incentive Award Plan 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:

(Shares in Millions)						2021						2020						2019
Basic						539						527						519
Diluted (a)						540						528						520

(a)Diluted common shares outstanding included common stock equivalents of 0.3 million, 1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

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10. 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 fund investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities — Fair values for debt securities are determined by a third-party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities 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 an 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. 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 in 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

Nuclear Decommissioning Fund

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 investment targets by asset class for the 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 $1.3 billion and $981 million as of Dec. 31, 2021 and 2020, respectively, and unrealized losses were $7 million and $5 million as of Dec. 31, 2021 and 2020, respectively.

Non-derivative instruments with recurring fair value measurements:

						Dec. 31, 2021
												Fair Value
(Millions of Dollars)						Cost						Level 1						Level 2						Level 3						NAV						Total
Nuclear decommissioning fund (a)
Cash equivalents						$	64					$	64					$	—					$	—					$	—					$	64
Commingled funds						856						—						—						—						1,294						1,294
Debt securities						631						—						666						9						—						675
Equity securities						411						1,222						1						—						—						1,223
Total						$	1,962					$	1,286					$	667					$	9					$	1,294					$	3,256

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $208 million of equity investments in unconsolidated subsidiaries and $164 million of rabbi trust assets and miscellaneous investments.

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						Dec. 31, 2020
												Fair Value
(Millions of Dollars)						Cost						Level 1						Level 2						Level 3						NAV						Total
Nuclear decommissioning fund (a)
Cash equivalents						$	40					$	40					$	—					$	—					$	—					$	40
Commingled funds						787						—						—						—						1,041						1,041
Debt securities						528						—						572						13						—						585
Equity securities						446						1,109						2						—						—						1,111
Total						$	1,801					$	1,149					$	574					$	13					$	1,041					$	2,777

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $165 million of equity investments in unconsolidated subsidiaries and $154 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2021 and 2020, 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 Dec. 31, 2021:

						Final Contractual Maturity
(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						$	4					$	149					$	208					$	314					$	675

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its SERP and deferred compensation plan.

Cost and fair value of assets held in rabbi trusts:

						Dec. 31, 2021
												Fair Value
(Millions of Dollars)						Cost						Level 1						Level 2						Level 3						Total
Rabbi Trusts (a)
Cash equivalents						$	20					$	20					$	—					$	—					$	20
Mutual funds						75						89						—						—						89
Total						$	95					$	109					$	—					$	—					$	109

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

						Dec. 31, 2020
												Fair Value
(Millions of Dollars)						Cost						Level 1						Level 2						Level 3						Total
Rabbi Trusts (a)
Cash equivalents						$	32					$	32					$	—					$	—					$	32
Mutual funds						60						70						—						—						70
Total						$	92					$	102					$	—					$	—					$	102

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

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 Dec. 31, 2021, accumulated other comprehensive loss related to settled interest rate derivatives included $5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2021, Xcel Energy had no unsettled interest rate derivatives.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.

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 unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Dec. 31, 2021, Xcel Energy had no 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)						Dec. 31, 2021						Dec. 31, 2020
MWh of electricity						80						87
MMBtu of natural gas						156						175

(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 on 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.

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As of Dec. 31, 2021, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $83 million or 38% of this credit exposure, had investment grade credit ratings from S&P, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $44 million or 20% of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $38 million or 18% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Eight of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)						2021						2020						2019
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1						$	(85)					$	(80)					$	(60)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges						4						(10)						(23)
After-tax net realized losses on derivative transactions reclassified into earnings						6						5						3
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31						$	(75)					$	(85)					$	(80)

Impact of derivative activity:

						Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)						Accumulated Other Comprehensive Loss						Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate						$	5					$	—
Total						$	5					$	—
Other derivative instruments
Electric commodity						$	—					$	32
Natural gas commodity						—						(4)
Total						$	—					$	28
Year Ended Dec. 31, 2020
Interest rate						$	(13)					$	—
Total						$	(13)					$	—
Other derivative instruments
Electric commodity						$	—					$	(5)
Natural gas commodity						—						(13)
Total						$	—					$	(18)
Year Ended Dec. 31, 2019
Interest rate						$	(30)					$	—
Total						$	(30)					$	—
Other derivative instruments
Electric commodity						$	—					$	8
Natural gas commodity						—						(9)
Total						$	—					$	(1)

						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:												Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)						Accumulated Other Comprehensive Loss						Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate						$	8		(a)			$	—					$	—
Total						$	8					$	—					$	—
Other derivative instruments
Commodity trading						$	—					$	—					$	63		(b)
Electric commodity						—						(23)			(c)			—
Natural gas commodity						—						5			(d)			(22)			(d)
Total						$	—					$	(18)					$	41
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate						$	7		(a)			$	—					$	—
Total						$	7					$	—					$	—
Other derivative instruments
Commodity trading						$	—					$	—					$	(1)		(b)
Electric commodity						—						(3)			(c)			—
Natural gas commodity						—						10			(d)			(13)			(d)
Total						$	—					$	7					$	(14)
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate						$	4		(a)			$	—					$	—
Total						$	4					$	—					$	—
Other derivative instruments
Commodity trading						$	—					$	—					$	2		(b)
Electric commodity						—						(5)			(c)			—
Natural gas commodity						—						2			(d)			(7)			(d)
Total						$	—					$	(3)					$	(5)

(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)Settlement losses related to natural gas operations are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 and 2019.

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Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and 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 Dec. 31, 2021 and 2020, there were $3 million and $4 million of derivative instruments in a liability position with such underlying contract provisions, respectively. 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 Dec. 31, 2021 and 2020, there were approximately $64 million and $60 million of derivative instruments in a liability position with such underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2021 and 2020.

Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

						Dec. 31, 2021																																				Dec. 31, 2020
						Fair Value																		Fair Value Total						Netting (a)						Total						Fair Value																		Fair Value Total						Netting (a)						Total
(Millions of Dollars)						Level 1						Level 2						Level 3															Level 1						Level 2						Level 3
Current derivative assets
Other derivative instruments:
Commodity trading						$	22					$	137					$	21					$	180					$	(134)					$	46					$	2					$	67					$	1					$	70					$	(52)					$	18
Electric commodity						—						—						57						57						(1)						56						—						—						20						20						(1)						19
Natural gas commodity						—						18						—						18						—						18						—						9						—						9						—						9
Total current derivative assets						$	22					$	155					$	78					$	255					$	(135)					120						$	2					$	76					$	21					$	99					$	(53)					46
PPAs (b)																																				3																																				3
Current derivative instruments																																				$	123																																			$	49
Noncurrent derivative assets
Other derivative instruments:
Commodity trading						$	16					$	63					$	89					$	168					$	(107)					$	61					$	8					$	66					$	8					$	82					$	(62)					$	20
Total noncurrent derivative assets						$	16					$	63					$	89					$	168					$	(107)					61						$	8					$	66					$	8					$	82					$	(62)					20
PPAs (b)																																				6																																				10
Noncurrent derivative instruments																																				$	67																																			$	30

						Dec. 31, 2021																																				Dec. 31, 2020
						Fair Value																		Fair Value Total						Netting (a)						Total						Fair Value																		Fair Value Total						Netting (a)						Total
(Millions of Dollars)						Level 1						Level 2						Level 3															Level 1						Level 2						Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading						$	19					$	148					$	20					$	187					$	(143)					$	44					$	4					$	64					$	17					$	85					$	(58)					$	27
Electric commodity						—						—						1						1						(1)						—						—						—						1						1						(1)						—
Natural gas commodity						—						8						—						8						—						8						—						9						—						9						—						9
Total current derivative liabilities						$	19					$	156					$	21					$	196					$	(144)					52						$	4					$	73					$	18					$	95					$	(59)					36
PPAs (b)																																				17																																				17
Current derivative instruments																																				$	69																																			$	53
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading						$	18					$	48					$	127					$	193					$	(128)					$	65					$	3					$	58					$	60					$	121					$	(47)					$	74
Total noncurrent derivative liabilities						$	18					$	48					$	127					$	193					$	(128)					65						$	3					$	58					$	60					$	121					$	(47)					74
PPAs (b)																																				40																																				57
Noncurrent derivative instruments																																				$	105																																			$	131

(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 as of Dec. 31, 2021 and 2020. At Dec. 31, 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include rights to reclaim cash collateral of $30 million and $6 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.

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Changes in Level 3 commodity derivatives:

						Year Ended Dec. 31
(Millions of Dollars)						2021						2020						2019
Balance at Jan. 1						$	(49)					$	4					$	29
Purchases						65						51						44
Settlements						(158)						(73)						(64)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)						49						(39)						(8)
Net gains recognized as regulatory assets and liabilities						112						8						3
Balance at Dec. 31						$	19					$	(49)					$	4

(a)Level 3 losses recognized in earnings are subject to offsetting gains of derivative 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 no transfers of amounts between levels for derivative instruments for Dec. 31, 2021, 2020 and 2019.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

						2021												2020
(Millions of Dollars)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Long-term debt, including current portion						$	22,380					$	25,232					$	20,066					$	24,412

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 Dec. 31, 2021 and 2020, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

11. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 2.03, 1.89 and 2.82% in 2021, 2020, and 2019, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants.

The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.

Obligations of the SERP and nonqualified plan as of Dec. 31, 2021 and 2020 were $43 million and $43 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 2021 and $6 million in 2020.

Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as long-term projected return levels.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

• Investment returns in 2021 were above the assumed level of 6.49%.

• Investment returns in 2020 were above the assumed level of 6.87%.

• Investment returns in 2019 were above the assumed level of 6.87%.

• In 2022, expected investment-return assumption is 6.49%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.

There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

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Plan Assets

For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:

						Dec. 31, 2021 (a)																														Dec. 31, 2020 (a)
(Millions of Dollars)						Level 1						Level 2						Level 3						Measured at NAV						Total						Level 1						Level 2						Level 3						Measured at NAV						Total
Cash equivalents						$	133					$	—					$	—					$	—					$	133					$	209					$	—					$	—					$	—					$	209
Commingled funds						1,324						—						—						1,143						2,467						1,462						—						—						1,115						2,577
Debt securities						—						959						5						—						964						—						714						4						—						718
Equity securities						67						—						—						—						67						77						—						—						—						77
Other						—						7						—						32						39						13						5						—						—						18
Total						$	1,524					$	966					$	5					$	1,175					$	3,670					$	1,761					$	719					$	4					$	1,115					$	3,599

(a)See Note 10 for further information regarding fair value measurement inputs and methods.

For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:

						Dec. 31, 2021 (a)																														Dec. 31, 2020 (a)
(Millions of Dollars)						Level 1						Level 2						Level 3						Measured at NAV						Total						Level 1						Level 2						Level 3						Measured at NAV						Total
Cash equivalents						$	28					$	—					$	—					$	—					$	28					$	27					$	—					$	—					$	—					$	27
Insurance contracts						—						52						—						—						52						—						50						—						—						50
Commingled funds						64						—						—						77						141						72						—						—						69						141
Debt securities						—						218						1						—						219						—						232						—						—						232
Other						—						2						—						—						2						—						2						—						—						2
Total						$	92					$	272					$	1					$	77					$	442					$	99					$	284					$	—					$	69					$	452

(a)See Note 10 for further information on fair value measurement inputs and methods.

No assets were transferred in or out of Level 3 for 2021 or 2020.

Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2020 to Dec. 31, 2021, due primarily to benefit payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:

						Pension Benefits												Postretirement Benefits
(Millions of Dollars)						2021						2020						2021						2020
Change in Benefit Obligation:
Obligation at Jan. 1						$	3,964					$	3,701					$	574					$	547
Service cost						104						95						2						1
Interest cost						104						125						15						18
Plan amendments						5						—						—						—
Actuarial (gain) loss						(94)						328						(41)						50
Plan participants’ contributions						—						—						8						8
Medicare subsidy reimbursements						—						—						2						1
Benefit payments (a)						(365)						(285)						(49)						(51)
Obligation at Dec. 31						$	3,718					$	3,964					$	511					$	574
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1						$	3,599					$	3,184					$	452					$	449
Actual return on plan assets						305						550						16						35
Employer contributions						131						150						15						11
Plan participants’ contributions						—						—						8						8
Benefit payments						(365)						(285)						(49)						(51)
Fair value of plan assets at Dec. 31						$	3,670					$	3,599					$	442					$	452
Funded status of plans at Dec. 31						$	(48)					$	(365)					$	(69)					$	(122)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets						$	19					$	—					$	33					$	6
Current liabilities						—						—						(4)						(7)
Noncurrent liabilities						(67)						(365)						(98)						(121)
Net amounts recognized						$	(48)					$	(365)					$	(69)					$	(122)

(a)Includes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge.

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						Pension Benefits												Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:						2021						2020						2021						2020
Discount rate for year-end valuation						3.08		%				2.71		%				3.09		%				2.65		%
Expected average long-term increase in compensation level						3.75						3.75						N/A						N/A
Mortality table						PRI-2012						PRI-2012						PRI-2012						PRI-2012
Health care costs trend rate — initial: Pre-65						N/A						N/A						5.30		%				5.50		%
Health care costs trend rate — initial: Post-65						N/A						N/A						4.90		%				5.00		%
Ultimate trend assumption — initial: Pre-65						N/A						N/A						4.50		%				4.50		%
Ultimate trend assumption — initial: Post-65						N/A						N/A						4.50		%				4.50		%
Years until ultimate trend is reached						N/A						N/A						4						5

Accumulated benefit obligation for the pension plan was $3,469 million and $3,693 million as of Dec. 31, 2021 and 2020, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

						Pension Benefits																		Postretirement Benefits
(Millions of Dollars)						2021						2020						2019						2021						2020						2019
Service cost						$	104					$	95					$	86					$	2					$	1					$	2
Interest cost						104						125						145						15						18						22
Expected return on plan assets						(206)						(208)						(203)						(18)						(19)						(21)
Amortization of prior service credit						(1)						(4)						(5)						(8)						(8)						(10)
Amortization of net loss						107						100						87						5						4						5
Settlement charge (a)						59						—						6						—						—						—
Net periodic pension cost (credit)						167						108						116						(4)						(4)						(2)
Effects of regulation						(46)						9						(1)						2						3						1
Net benefit cost (credit) recognized for financial reporting						$	121					$	117					$	115					$	(2)					$	(1)					$	(1)
Significant Assumptions Used to Measure Costs:
Discount rate						2.71		%				3.49		%				4.31		%				2.65		%				3.47		%				4.32		%
Expected average long-term increase in compensation level						3.75						3.75						3.75						—						—						—
Expected average long-term rate of return on assets						6.49						6.87						6.87						4.10						4.50						4.50

(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2021 and 2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $59 million and $6 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $7 million and $1 million was recorded in the consolidated statements of income in 2021 and 2019, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.

						Pension Benefits												Postretirement Benefits
(Millions of Dollars)						2021						2020						2021						2020
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss						$	978					$	1,333					$	81					$	126
Prior service credit						(9)						(11)						(7)						(15)
Total						$	969					$	1,322					$	74					$	111
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets						$	74					$	82					$	—					$	—
Noncurrent regulatory assets						846						1,181						90						125
Current regulatory liabilities						—						—						(1)						(1)
Noncurrent regulatory liabilities						—						—						(19)						(18)
Deferred income taxes						13						15						1						1
Net-of-tax accumulated other comprehensive income						36						44						3						4
Total						$	969					$	1,322					$	74					$	111

Measurement date						Dec. 31, 2021						Dec. 31, 2020						Dec. 31, 2021						Dec. 31, 2020

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Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2019 - 2022 to meet minimum funding requirements.

Voluntary and required pension funding contributions:

• $50 million in January 2022.

• $131 million in 2021.

• $150 million in 2020.

• $154 million in 2019.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.

Voluntary postretirement funding contributions:

• Expects to contribute approximately $9 million during 2022.

• $15 million during 2021.

• $11 million during 2020.

• $15 million during 2019.

Targeted asset allocations:

						Pension Benefits												Postretirement Benefits
						2021						2020						2021						2020
Domestic and international equity securities						33		%				35		%				15		%				15		%
Long-duration fixed income securities						37						35						—						—
Short-to-intermediate fixed income securities						11						13						71						72
Alternative investments						17						15						8						9
Cash						2						2						6						4
Total						100		%				100		%				100		%				100		%

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.

Plan Amendments —

In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022.

There were no significant plan amendments made in 2020 which affected the postretirement benefit obligation.

In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.

Projected Benefit Payments

Xcel Energy’s projected benefit payments:

(Millions of Dollars)						Projected Pension Benefit Payments						Gross Projected Postretirement Health Care Benefit Payments						Expected Medicare Part D Subsidies						Net Projected Postretirement Health Care Benefit Payments
2022						$	323					$	42					$	2					$	40
2023						257						41						2						39
2024						253						40						2						38
2025						251						38						2						36
2026						245						37						2						35
2027-2031						1,156						165						13						152

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $43 million in 2021, $42 million in 2020 and $39 million in 2019.

Multiemployer Plans

NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans.

Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

12. Commitments and Contingencies

Legal

Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.

In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.

Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.

One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.).

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.

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. In July 2021, the settlement was approved.

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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 its Minnesota jurisdiction, 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. The OAG recommended the MPUC deny recovery of up to $179 million, the largest recommendation among the intervenor positions.

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. An MPUC decision is expected in the summer of 2022.

Sherco — In 2018, NSP-Minnesota and Southern Minnesota Municipal Power Agency (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.

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.

In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.

In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. 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 of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, Southern Minnesota Municipal Power Agency and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards.

NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the first quarter of 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 new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds.

In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint.

In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not 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. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in ROE for the first complaint period, second complaint period and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.

The MISO TOs and various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. Oral arguments were held in late 2021 and a decision is expected by the end of the third quarter of 2022.

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SPP OATT Upgrade Costs — Costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade under the SPP OATT. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015.

In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In August 2021, the D.C Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates. The timing of these refunds is uncertain.

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. FERC has asked that this appeal be stayed until early 2022, in order to provide FERC with time to issue an order on SPS’ April 2018 rehearing request. FERC’s order is expected in the first quarter of 2022. The D.C. Circuit appeal may resume after that FERC order is issued.

Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2021, the full-year net capacity factor was 48.4%, resulting in no refund liability for 2021.

Contract Termination — SPS and LP&L are parties to a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (lump sum or annual installments), to the benefit of SPS’ remaining customers. LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The settlement agreement is subject to approval by the PUCT and FERC.

Comanche Unit 3 Litigation — In February 2021, the joint owners of Comanche Unit 3 (CORE Electric Cooperative, formerly known as Intermountain Rural Electrical Association, and Holy Cross Electric) served PSCo with a notice of claim related to Comanche Unit 3's operation and availability.

In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado state court seeking an unspecified amount of damages. CORE Electric Cooperative alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo filed a Motion to Dismiss several of CORE’s claims. In January 2022 the Court granted PSCo’s Motion to Dismiss CORE’s claim for damages for replacement power costs, claims for unjust enrichment and declaratory judgment. CORE’s claims for breach of contract, breach of the duty of good faith and fair dealing, and waste remain pending.

In November 2021, PSCo resolved all differences with Holy Cross Electric related to their claim.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process.

Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination.

Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.

Historical MGP, Landfill and Disposal Sites

Xcel Energy is currently investigating, remediating or performing post-closure actions at 16 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).

Xcel Energy has recognized its best estimate of costs/liabilities from final resolution of these issues; however, the outcome and timing are 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 eight regulated ash units in operation.

Xcel Energy is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, increases above background concentrations were detected at four locations. Based on further assessments, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. The total cost is uncertain, but could be up to $35 million. PSCo is continuing to assess the financial and regulatory impacts.

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In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. This final rule required Xcel Energy to expedite closure plans for two impoundments.

In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined 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 also built an alternative collection and treatment system to remove the Comanche Station bottom ash pond from service. The total cost of the alternate treatment system is approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline, but was not able to remove the pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the EPA addressing the closure deadline as well as other potential issues. PSCo will also now proceed with closure of the pond, at an estimated cost of $3 million.

Closure costs for existing impoundments are included in the calculation of the ARO.

Federal CWA Waters of the U.S. Rule — Xcel Energy is monitoring ongoing changes to the definition of Waters of the U.S. under the CWA. Regardless of which definition is applicable in the states in which we operate, Xcel Energy does not anticipate that compliance costs will be material.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.

The retirement of units affected by the final ELG rule is subject to regulatory approval. The exact total cost of ELG compliance is therefore uncertain but Xcel Energy does not anticipate that compliance costs will be material.

Federal CWA Section 316(b) — The federal CWA 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 six NSP-Minnesota plants and two 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

Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. The regional haze first planning period requirements developed by Minnesota and Colorado were approved by the EPA in 2012 and implemented by 2014 and 2016, respectively. Texas’ first regional haze plan has undergone federal review.

All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to Xcel Energy facilities are expected to be minimal.

BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the D.C. Circuit that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking. The EPA reaffirmed the rule in August 2020 with minor changes.

The 2020 EPA Action has been challenged. All pending actions could be consolidated and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is unclear.

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 SO2 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 SO2 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.

Implementation of the NAAQS for SO**2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with one exception. The EPA issued final designations, which found the area near the SPS Harrington plant as “unclassifiable.” The area near the Harrington plant was monitored for the three years ending in 2019 and the monitoring showed the area to be exceeding the standard.

To address this issue, SPS negotiated an order with the TCEQ providing for the end of coal combustion and the conversion of the Harrington plant to a natural gas fueled facility by Jan. 1, 2025.

Xcel Energy believes compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.

AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.

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Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $3.3 billion and $2.8 billion for 2021 and 2020, respectively.

Xcel Energy’s AROs were as follows:

(Millions of Dollars)						Jan. 1, 2021						Amounts Incurred (a)												Accretion						Cash Flow Revisions (b)						Dec. 31, 2021 (c)
Electric
Nuclear						$	1,957					$	—											$	99					$	—					$	2,056
Wind						360						101												17						—						478
Steam, hydro and other production						264						6												10						8						288
Distribution						46						—												1						—						47
Natural gas
Transmission and distribution						252						—												10						9						271
Miscellaneous						3						—												—						5						8
Common
Miscellaneous						1						—												—						—						1
Non-utility
Miscellaneous						1						—												1						—						2
Total liability						$	2,884					$	107											$	138					$	22					$	3,151

(a)Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in NSP-Minnesota.

(b)In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.

(c)There were no ARO amounts settled in 2021.

(Millions of Dollars)						Jan. 1, 2020						Amounts Incurred (a)						Amounts Settled (b)						Accretion						Cash Flow Revisions (c)						Dec. 31, 2020
Electric
Nuclear						$	2,068					$	—					$	—					$	105					$	(216)					$	1,957
Steam, hydro and other production						202						—						(5)						9						58						264
Wind						146						149						(3)						8						60						360
Distribution						44						—						—						2						—						46
Natural gas
Transmission and distribution						236						—						—						10						6						252
Miscellaneous						3						—						—						—						—						3
Common
Miscellaneous						1						—						—						—						—						1
Non-utility
Miscellaneous						1						—						—						—						—						1
Total liability						$	2,701					$	149					$	(8)					$	134					$	(92)					$	2,884

(a)Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore).

(b)Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects.

(c)In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.

Indeterminate AROs — Other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2021. Therefore, an ARO was not recorded for these facilities.

Nuclear

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.5 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.0 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.

NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.

All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.

NSP-Minnesota could be subject to annual maximum assessments of $11 million for business interruption insurance and $33 million for property damage insurance if losses exceed accumulated reserve funds.

Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 47 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension. NSP-Minnesota expects a decision by year-end 2023.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.

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Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.

Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%.

Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.

NSP-Minnesota had $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2021. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO.

						Regulatory Basis
(Millions of Dollars)						2021						2020
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)						$	3,012					$	3,012
Effect of escalating costs						1,006						844
Estimated decommissioning cost obligation (in current dollars)						4,018						3,856
Effect of escalating costs to payment date						7,187						7,349
Estimated future decommissioning costs (undiscounted)						11,205						11,205
Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively)						(4,651)						(4,181)
Discounted decommissioning cost obligation						$	6,554					$	7,024
Assets held in external decommissioning trust						$	3,256					$	2,777
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation						3,298						4,247

Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.

Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)						2021						2020
Discounted decommissioning cost obligation - regulated basis						$	6,554					$	7,024
Differences in discount rate and market risk premium						(2,209)						(2,628)
O&M costs not included for GAAP						(1,584)						(1,734)
ARO differences between 2020 and 2014 cost studies						(705)						(705)
Nuclear production decommissioning ARO - GAAP						$	2,056					$	1,957

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)						2021						2020						2019
Annual decommissioning recorded as depreciation expense: (a) (b)						$	22					$	20					$	20

(a)Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

(b)Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.

The 2017 nuclear decommissioning filing, effective Jan. 1, 2019, has been approved by the MPUC. In March 2020, the MPUC approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. In December 2020, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2022. In December 2021, NSP-Minnesota submitted a Petition for approval of the 2022 - 2024 Nuclear Decommissioning Study and Assumptions. Contemplated but not proposed in this filing, was the 10-year extension of the license to operate the Monticello Plant, moving the planned retirement date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan Supplement does include a 10-year extension of the license. On Feb. 8, 2022, the MPUC approved the 10-year extension.

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. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted average of 4.0%). Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
PPAs						$	1,656					$	1,650
Other						225						212
Gross operating lease ROU assets						1,881						1,862
Accumulated amortization						(590)						(372)
Net operating lease ROU assets						$	1,291					$	1,490

ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities.

Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.

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Finance lease ROU assets:

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
Gas storage facilities						$	201					$	201
Gas pipeline						21						21
Gross finance lease ROU assets						222						222
Accumulated amortization						(97)						(90)
Net finance lease ROU assets						$	125					$	132

Components of lease expense:

(Millions of Dollars)						2021						2020						2019
Operating leases
PPA capacity payments						$	251					$	238					$	221
Other operating leases (a)						36						26						34
Total operating lease expense (b)						$	287					$	264					$	255
Finance leases
Amortization of ROU assets						$	7					$	7					$	6
Interest expense on lease liability						17						18						19
Total finance lease expense						$	24					$	25					$	25

(a)Includes short-term lease expense of $5 million for 2021, 2020 and 2019.

(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 Dec. 31, 2021:

(Millions of Dollars)						PPA (a) (b) Operating Leases						Other Operating Leases						Total Operating Leases						Finance Leases (c)
2022						$	229					$	27					$	256					$	12
2023						221						26						247						12
2024						209						22						231						12
2025						189						16						205						10
2026						146						12						158						9
Thereafter						416						81						497						187
Total minimum obligation						1,410						184						1,594						242
Interest component of obligation						(209)						(34)						(243)						(170)
Present value of minimum obligation						$	1,201					150						1,351						72
Less current portion																		(205)						(3)
Noncurrent operating and finance lease liabilities																		$	1,146					$	69
Weighted-average remaining lease term in years																		8.9						36.1

(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

(b)PPA operating leases contractually expire at various dates through 2039.

(c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.

PPAs and Fuel Contracts

Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2033, contain minimum energy purchase commitments. Total energy payments on those contracts were $149 million, $112 million and $102 million in 2021, 2020 and 2019, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $69 million, $75 million and $86 million in 2021, 2020 and 2019, respectively.

Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.

At Dec. 31, 2021, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:

(Millions of Dollars)						Capacity						Energy (a)
2022						$	75					$	165
2023						77						169
2024						72						174
2025						29						53
2026						12						10
Thereafter						12						38
Total						$	277					$	609

(a)Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2022 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2021:

(Millions of Dollars)						Coal						Nuclear fuel						Natural gas supply						Natural gas supply and transportation
2022						$	620					$	89					$	477					$	292
2023						233						109						75						224
2024						147						82						4						172
2025						29						119						—						156
2026						31						29						—						149
Thereafter						34						309						—						571
Total						$	1,094					$	737					$	556					$	1,564

VIEs

PPAs — 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. Xcel Energy has determined that certain IPPs are VIEs. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.

Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. 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.

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The utility subsidiaries had approximately 4,062 MW of capacity under long-term PPAs at both Dec. 31, 2021 and 2020 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.

SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary of TUCO because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not align with the partners’ proportional equity ownership.

Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Xcel Energy’s risk of loss for these partnerships is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be, provided to the limited partnerships by Eloigne or NSP-Wisconsin.

Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships:

(Millions of Dollars)						Dec. 31, 2021						Dec. 31, 2020
Current assets						$	7					$	7
Property, plant and equipment, net						37						38
Other noncurrent assets						1						1
Total assets						$	45					$	46
Current liabilities						$	7					$	8
Mortgages and other long-term debt payable						27						25
Other noncurrent liabilities						1						1
Total liabilities						$	35					$	34

Other

Technology Agreements — Xcel Energy has several contracts for information technology services that extend through 2022. The contracts are cancelable, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $103 million, $110 million and $101 million associated with these contracts in 2021, 2020 and 2019, respectively.

Committed minimum payments under these obligations are $15 million in 2022.

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. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.

As of Dec. 31, 2021 and 2020, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $60 million and $62 million at Dec. 31, 2021 and 2020 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.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 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)
Other comprehensive loss before reclassifications (net of taxes of $1 and $—, respectively)						4						—						4
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $2 and $—, respectively)						6			(a)			—						6
Amortization of net actuarial loss (net of taxes of $— and $3, respectively)						—						8			(b)			8
Net current period other comprehensive income						10						8						18
Accumulated other comprehensive loss at Dec. 31						$	(75)					$	(48)					$	(123)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

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						2020
(Millions of Dollars)						Gains and Losses on Cash Flow Hedges						Defined Benefit Pension and Postretirement Items						Total
Accumulated other comprehensive loss at Jan. 1						$	(80)					$	(61)					$	(141)
Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively)						(10)						(5)						(15)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $2 and $—, respectively)						5			(a)			—						5
Amortization of net actuarial loss (net of taxes of $— and $3, respectively)						—						10			(b)			10
Net current period other comprehensive (loss) income						(5)						5						—
Accumulated other comprehensive loss at Dec. 31						$	(85)					$	(56)					$	(141)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

14. Segment Information

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, investments in rental housing projects that qualify for low-income housing tax credits and the operations of MEC until July 2020.

Xcel Energy had equity method investments of $208 million and $165 million as of Dec. 31, 2021 and 2020, 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:

(Millions of Dollars)						2021						2020						2019
Regulated Electric
Operating revenues — external						$	11,205					$	9,802					$	9,575
Intersegment revenue						2						2						1
Total revenues						$	11,207					$	9,804					$	9,576
Depreciation and amortization						1,855						1,673						1,535
Interest charges and financing costs						568						534						500
Income tax (benefit) expense						(96)						1						125
Net income						1,478						1,407						1,288
Regulated Natural Gas
Operating revenues — external						$	2,132					$	1,636					$	1,868
Intersegment revenue						2						1						2
Total revenues						$	2,134					$	1,637					$	1,870
Depreciation and amortization						254						252						219
Interest charges and financing costs						75						71						69
Income tax expense						54						17						48
Net income						231						190						195
All Other
Total revenues						$	94					$	88					$	86
Depreciation and amortization						12						23						11
Interest charges and financing costs						173						193						167
Income tax benefit						(28)						(24)						(45)
Net loss						(112)						(124)						(111)
Consolidated Total
Total revenues						$	13,435					$	11,529					$	11,532
Reconciling eliminations						(4)						(3)						(3)
Total operating revenues						$	13,431					$	11,526					$	11,529
Depreciation and amortization						2,121						1,948						1,765
Interest charges and financing costs						816						798						736
Income tax (benefit) expense						(70)						(6)						128
Net income						1,597						1,473						1,372