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.

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, 2022. 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, 2022, 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, 2023									Feb. 23, 2023

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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, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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, 2023

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
	2022		2021		2020
Operating revenues
Electric	$	12,123	$	11,205	$	9,802
Natural gas	3,080		2,132		1,636
Other	107		94		88
Total operating revenues	15,310		13,431		11,526

Operating expenses
Electric fuel and purchased power	5,005		4,733		3,512
Cost of natural gas sold and transported	1,910		1,081		689
Cost of sales — other	44		38		37
Operating and maintenance expenses	2,491		2,321		2,324
Conservation and demand side management expenses	331		304		288
Depreciation and amortization	2,413		2,121		1,948
Taxes (other than income taxes)	688		630		612
Total operating expenses	12,882		11,228		9,410

Operating income	2,428		2,203		2,116

Other (expense) income, net	(13)		5		(6)
Earnings from equity method investments	36		62		40
Allowance for funds used during construction — equity	75		73		115

Interest charges and financing costs
Interest charges — includes other financing costs of $31, $29 and $28, respectively	953		842		840
Allowance for funds used during construction — debt	(28)		(26)		(42)
Total interest charges and financing costs	925		816		798

Income before income taxes	1,601		1,527		1,467
Income tax benefit	(135)		(70)		(6)
Net income	$	1,736	$	1,597	$	1,473

Weighted average common shares outstanding:
Basic	547		539		527
Diluted	547		540		528

Earnings per average common share:
Basic	$	3.18	$	2.96	$	2.79
Diluted	3.17		2.96		2.79

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
	2022		2021		2020

Net income	$	1,736	$	1,597	$	1,473
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical gains (losses) arising during the period, net of tax of $1, $— and $(2), respectively	5		—		(5)
Reclassification of losses to net income, net of tax of $1, $3 and $3, respectively	4		8		10
Derivative instruments:
Net fair value increase (decrease), net of tax of $6, $1 and $(3), respectively	16		4		(10)
Reclassification of losses to net income, net of tax of $2, $2 and $2, respectively	5		6		5

Total other comprehensive income	30		18		—
Total comprehensive income	$	1,766	$	1,615	$	1,473
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
	2022		2021		2020
Operating activities
Net income	$	1,736	$	1,597	$	1,473
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	2,436		2,143		1,959
Nuclear fuel amortization	118		114		123
Deferred income taxes	(140)		(79)		(8)
Allowance for equity funds used during construction	(75)		(73)		(115)
Earnings from equity method investments	(36)		(62)		(40)
Dividends from equity method investments	37		42		42
Provision for bad debts	73		60		60
Share-based compensation expense	20		31		73

Changes in operating assets and liabilities:
Accounts receivable	(429)		(164)		(154)
Accrued unbilled revenues	(243)		(149)		(3)
Inventories	(203)		(126)		(80)
Other current assets	(58)		(34)		(45)
Accounts payable	195		138		(33)
Net regulatory assets and liabilities	570		(973)		(144)
Other current liabilities	102		(1)		29
Pension and other employee benefit obligations	(49)		(135)		(125)
Other, net	(122)		(140)		(164)
Net cash provided by operating activities	3,932		2,189		2,848

Investing activities
Capital/construction expenditures	(4,638)		(4,244)		(5,369)
Sale of MEC	—		—		684
Purchase of investment securities	(1,332)		(757)		(1,398)
Proceeds from the sale of investment securities	1,297		743		1,378
Other, net	20		(29)		(35)
Net cash used in investing activities	(4,653)		(4,287)		(4,740)

Financing activities
(Repayments of) proceeds from short-term borrowings, net	(192)		421		(11)
Proceeds from issuances of long-term debt	2,164		2,710		2,940
Repayments of long-term debt	(601)		(417)		(1,001)
Proceeds from issuance of common stock	322		366		727
Dividends paid	(1,012)		(935)		(856)
Other, net	(15)		(10)		(26)
Net cash provided by financing activities	666		2,135		1,773

Net change in cash and cash equivalents	(55)		37		(119)
Cash, cash equivalents and restricted cash at beginning of period	166		129		248
Cash, cash equivalents and restricted cash at end of period	$	111	$	166	$	129

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(887)	$	(788)	$	(758)
Cash (paid) received for income taxes, net	(15)		(4)		12

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	626	$	501	$	400
Inventory transfers to property, plant and equipment	78		87		275
Operating lease right-of-use assets	141		8		369
Allowance for equity funds used during construction	75		73		115
Issuance of common stock for reinvested dividends and/or equity awards	57		60		67
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
	2022		2021
Assets
Current assets
Cash and cash equivalents	$	111	$	166
Accounts receivable, net	1,373		1,018
Accrued unbilled revenues	1,105		862
Inventories	803		631
Regulatory assets	1,059		1,106
Derivative instruments	279		123
Prepaid taxes	54		44
Prepayments and other	360		289
Total current assets	5,144		4,239

Property, plant and equipment, net	48,253		45,457

Other assets
Nuclear decommissioning fund and other investments	3,234		3,628
Regulatory assets	2,871		2,738
Derivative instruments	93		67
Operating lease right-of-use assets	1,204		1,291
Other	389		431
Total other assets	7,791		8,155
Total assets	$	61,188	$	57,851

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,151	$	601
Short-term debt	813		1,005
Accounts payable	1,804		1,409
Regulatory liabilities	418		271
Taxes accrued	569		569
Accrued interest	217		209
Dividends payable	268		249
Derivative instruments	76		69
Operating lease liabilities	217		205
Other	545		459
Total current liabilities	6,078		5,046

Deferred credits and other liabilities
Deferred income taxes	4,756		4,894
Deferred investment tax credits	48		53
Regulatory liabilities	5,569		5,405
Asset retirement obligations	3,380		3,151
Derivative instruments	113		105
Customer advances	181		196
Pension and employee benefit obligations	390		306
Operating lease liabilities	1,038		1,146
Other	147		158
Total deferred credits and other liabilities	15,622		15,414

Commitments and contingencies
Capitalization
Long-term debt	22,813		21,779
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 549,578,018 and 544,025,269 shares outstanding at Dec. 31, 2022 and Dec. 31, 2021, respectively	1,374		1,360
Additional paid in capital	8,155		7,803
Retained earnings	7,239		6,572
Accumulated other comprehensive loss	(93)		(123)
Total common stockholders’ equity	16,675		15,612
Total liabilities and equity	$	61,188	$	57,851

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, 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
Repurchases 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 loss								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

Net income						1,736				1,736
Other comprehensive income								30		30
Dividends declared on common stock ($1.95 per share)						(1,066)				(1,066)
Issuances of common stock	5,552,749	14		345						359

Share-based compensation				7		(3)				4

Balance at Dec. 31, 2022	549,578,018	$	1,374	$	8,155	$	7,239	$	(93)	$	16,675

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 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:


Nonregulated Subsidiary						Purpose
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 Minnesota community solar gardens.

Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:


Direct Subsidiary
Xcel Energy Wholesale Group Inc.
Xcel Energy Market Holdings Inc.
Xcel Energy Ventures Inc.
Xcel Energy Retail Holdings Inc.
Xcel Energy Communication Group, Inc.
Xcel Energy International Inc.
Xcel Energy Transmission Holding Company, LLC
Nicollet Holdings Company, LLC
Xcel Energy Nuclear Services Holdings, LLC
Xcel Energy Services Inc.

Xcel Energy 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. The equity method of accounting is used for its investments in EIP funds and WYCO.

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

The 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, 2022 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 — The 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 and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other information available. 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. 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. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities.

Rates are utilized 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, refundable to utility customers over the remaining life of the related assets.

Xcel Energy anticipates that a tax rate increase would predominantly 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 over the book depreciable lives of the related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities.

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. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes.

Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the 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.

Interest and penalties related to income taxes are reported 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.

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.

Depreciation expense is recorded 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 are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. 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 3.7% for 2022, 3.5% for 2021 and 3.4% for 2020.

See Note 3 for further information.

AROs — Xcel Energy records AROs as a liability for the fair value of an ARO to be recognized in the period incurred (if it can be reasonably estimated), with the offsetting/associated 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 typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts 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 normally performed at least every three years and submitted to the state commissions for approval. Due to other regulatory activity, the next decommissioning study has been deferred one year until 2024.

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.

Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable 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.

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Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. 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.

A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are 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, 2022 and 2021, the allowance for bad debts was $122 million and $106 million, respectively.

Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:


(Millions of Dollars)	Dec. 31, 2022		Dec. 31, 2021
Inventories
Materials and supplies	$	330	$	289
Fuel	201		182
Natural gas	272		160
Total inventories	$	803	$	631

Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and EIP funds, which requires Xcel Energy’s recognition of its share of these investees’ results, 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.

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate 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, quoted prices for similar contracts or internally prepared valuation models may be used 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 determine fair value for each security.

See Notes 10 and 11 for further information.

Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates, and utility commodity prices, 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.

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 they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.

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 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.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity and 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.

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Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which 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, 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.

Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any 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, 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 on a net basis in electric operating revenues in the consolidated statements of income.


2. Accounting Pronouncements

As of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy’s consolidated financial statements.


3. Property, Plant and Equipment

Major classes of property, plant and equipment


(Millions of Dollars)	Dec. 31, 2022		Dec. 31, 2021
Property, plant and equipment, net
Electric plant	$	49,639	$	48,680
Natural gas plant	8,514		7,758
Common and other property	2,970		2,602
Plant to be retired (a)	2,217		1,200
CWIP	2,124		1,969
Total property, plant and equipment	65,464		62,209
Less accumulated depreciation	(17,502)		(17,060)
Nuclear fuel	3,183		3,081
Less accumulated amortization	(2,892)		(2,773)
Property, plant and equipment, net	$	48,253	$	45,457

(a)Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and coal generation assets at Harrington pending facility gas conversion for SPS. Following the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Dec. 31, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion as well as the removal of Comanche Unit 1 that was retired in 2022. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2022:


(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3	$	623	$	468	59	%
Sherco common facilities	180		115		80
Sherco substation	5		4		59
Electric transmission:
Grand Meadow	11		3		50
Huntley Wilmarth	49		1		50
CapX2020	818		124		51
Total NSP-Minnesota (a)	$	1,686	$	715

(a)Projects additionally include $4 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	$	20	37	%
CapX2020	166		34		80
Total NSP-Wisconsin (a)	$	343	$	54

(a)Projects additionally include $1 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	$	157	$	99	76	%
Hayden Unit 2	151		81		37
Hayden common facilities	42		29		53
Craig Units 1 and 2	82		51		10
Craig common facilities	39		24		7
Comanche Unit 3	918		174		67
Comanche common facilities	28		3		82
Electric transmission:
Transmission and other facilities	186		72		Various
Gas transmission:
Rifle, CO to Avon, CO	25		9		60
Gas transmission compressor	8		2		50
Total PSCo (a)	$	1,636	$	544

(a)Projects additionally include $10 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, 2022				Dec. 31, 2021 (a)
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	11	Various	$	22	$	1,069	$	77	$	944
Net AROs (b)	1, 12	Various	—		339		—		(112)
Deferred natural gas, electric, steam energy/fuel costs		One to five years	581		299		504		543
Recoverable deferred taxes on AFUDC		Plant lives	—		292		—		289
Excess deferred taxes — TCJA	7	Various	13		205		14		219
Depreciation differences		One to 12 years	17		193		16		173
Environmental remediation costs	1, 12	Various	20		92		14		92
Benson biomass PPA termination and asset purchase		Six years	10		45		10		55
PI extended power uprate		12 years	4		42		4		46
Conservation programs (c)	1	One to two years	16		36		21		35
Purchased power contract costs		Term of related contract	10		36		9		45
State commission adjustments		Plant lives	1		33		1		32
Losses on reacquired debt		Term of related debt	3		32		3		35
Contract valuation adjustments (d)	1, 10	Term of related contract	28		28		22		34
Grid modernization costs		Various	14		24		—		36
Gas pipeline inspection and remediation costs		One to two years	42		13		33		12
Nuclear refueling outage costs	1	One to two years	30		12		37		16
Renewable resources and environmental initiatives		One to two years	50		6		170		48
Texas revenue surcharges		Less than one year	69		—		20		64
Sales true-up and revenue decoupling		One to two years	54		—		33		56


Other		Various	75		75		118		76
Total regulatory assets			$	1,059	$	2,871	$	1,106	$	2,738

(a)Prior period amounts have been restated to conform with current year presentation.

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

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

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

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Components of regulatory liabilities:


(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2022				Dec. 31, 2021 (a)
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (b)	7	Various	$	9	$	3,110	$	26	$	3,230
Plant removal costs	1, 12	Various	—		1,819		—		1,655
Effects of regulation on employee benefit costs (c)		Various	—		247		—		235
Renewable resources and environmental initiatives		Various	6		173		1		101
Revenue decoupling		One to two years	—		77		9		41
ITC deferrals	1	Various	1		61		—		53
Formula rates		One to two years	32		17		19		11
Contract valuation adjustments (d)	1, 10	One to two years	175		1		56		1
Deferred natural gas, electric, steam energy/fuel costs		Less than one year	39		—		50		—
Conservation programs (e)	1	Less than one year	72		—		42		—
DOE settlement		Various	12		3		14		14
Other		Various	72		61		54		64
Total regulatory liabilities (f)			$	418	$	5,569	$	271	$	5,405

(a)Prior period amounts have been restated to conform with current year presentation.

(b)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.

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

(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.

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

(f)Revenue subject to refund of $67 million and $17 million for 2022 and 2021, respectively, is included in other current liabilities.

Xcel Energy’s regulatory assets not earning a return include the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed). In addition, regulatory assets included $1,020 million and $1,718 million at Dec. 31, 2022 and 2021 respectively, of past expenditures not earning a return. Amounts are predominately related to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts.


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 other borrowings outstanding:


(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2022			Year Ended Dec. 31
	2022			2021			2020
Borrowing limit	$	3,550		$	3,550		$	3,100		$	3,100
Amount outstanding at period end	813			813			1,005			584
Average amount outstanding	416			552			1,399			1,126
Maximum amount outstanding	813			1,357			2,054			2,080
Weighted average interest rate, computed on a daily basis	4.20		%	1.47		%	0.57		%	1.45		%
Weighted average interest rate at period end	4.66			4.66			0.31			0.23

Bilateral Credit Agreement — In April 2022, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of Dec. 31, 2022, NSP-Minnesota had $54 million outstanding letters of credit under the $75 million 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, 2022 and 2021, there were $43 million and $19 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.

Amended Credit Agreements — In September 2022*,* Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $3.55 billion. The amended credit agreements have substantially the same terms and conditions as the prior agreements, with the following changes:

Maturities extended from June 2024 to September 2027.
Borrowing limit for Xcel Energy Inc. increased from $1.25 billion to $1.5 billion.
Borrowing limit for NSP-Minnesota increased from $500 million to $700 million.

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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)
	2022		2021
Xcel Energy Inc. (c)	60	%	60	%	$	350	2
NSP-Minnesota	48		47		150		2
NSP-Wisconsin	47		49		N/A		1
SPS	46		47		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.

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, 2022, 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, 2022:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	$	1,500	$	231	$	1,269
PSCo	700		321		379
NSP-Minnesota	700		222		478
SPS	500		36		464
NSP-Wisconsin	150		47		103
Total	$	3,550	$	857	$	2,693

(a)These credit facilities mature in September 2027.

(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, 2022 and 2021.

Long-Term Borrowings and Other Financing Instruments

Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders.

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	2022		2021

Unsecured senior notes	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		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	3.40	June 1, 2030	600		600
Unsecured senior notes (a)	2.35	Nov. 15, 2031	300		300
Unsecured senior notes (b)	4.60	June 1, 2032	700		—
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			(7)		(8)
Unamortized debt issuance cost			(35)		(33)
Current maturities			(500)		—
Total long-term debt			$	5,338	$	5,139

(a)2021 financing.

(b)2022 financing.


NSP-Minnesota
Financing Instrument	Interest Rate		Maturity Date	2022		2021
First mortgage bonds	2.15	%	Aug. 15, 2022	$	—	$	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		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	2.60		June 1, 2051	700		700
First mortgage bonds (a)	3.20		April 1,2052	425		425
First mortgage bonds (b)	4.50		June 1, 2052	500		—
Other long-term debt				3		3
Unamortized discount				(45)		(44)
Unamortized debt issuance cost				(66)		(62)
Current maturities				(400)		(300)
Total long-term debt				$	6,542	$	6,447

(a)2021 financing.

(b)2022 financing.

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NSP-Wisconsin
Financing Instrument	Interest Rate	Maturity Date	2022		2021

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	3.05	May 1, 2051	100		100
First mortgage bonds (a)	2.82	May 1, 2051	100		100
First mortgage bonds (b)	4.86	Sept. 15, 2052	100		—
Other long-term debt			—		1
Unamortized discount			(3)		(4)
Unamortized debt issuance cost			(11)		(10)

Total long-term debt			$	1,086	$	987

(a)2021 financing.

(b)2022 financing.


PSCo
Financing Instrument	Interest Rate		Maturity Date	2022		2021
First mortgage bonds	2.25	%	Sept. 15, 2022	$	—	$	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	1.90		Jan. 15, 2031	375		375
First mortgage bonds (a)	1.875		June 15, 2031	750		750
First mortgage bonds (b)	4.10		June 1, 2032	300		—
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	2.70		Jan. 15, 2051	375		375
First mortgage bonds (b)	4.50		June 1, 2052	400		—
Unamortized discount				(37)		(33)
Unamortized debt issuance cost				(53)		(50)
Current maturities				(250)		(300)
Total long-term debt				$	6,610	$	6,167

(a)2021 financing.

(b)2022 financing.


SPS
Financing Instrument	Interest Rate		Maturity Date	2022		2021
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	3.15		May 1, 2050	350		350
First mortgage bonds (a)	3.15		May 1, 2050	250		250
First mortgage bonds (b)	5.15		June 1, 2052	200		—
Unamortized discount				(10)		(9)
Unamortized debt issuance cost				(29)		(28)
Total long-term debt				$	3,211	$	3,013

(a)2020 financing re-opened in 2021.

(b)2022 financing.


Other Subsidiaries
Financing Instrument	Interest Rate	Maturity Date	2022		2021
Various Eloigne affordable housing project notes	0.00% - 8.00%	2024 - 2055	$	27	$	27
Current maturities			(1)		(1)
Total long-term debt			$	26	$	26

Maturities of long-term debt:


(Millions of Dollars)
2023	$	1,151
2024	552
2025	1,103
2026	501
2027	501

Deferred Financing Costs — Deferred financing costs of approximately $193 million and $184 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2022 and 2021, respectively.

Equity through DRIP and Benefits Program — Xcel Energy issued $84 million and $74 million of equity through the DRIP and benefits programs in 2022 and 2021, respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.

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. In 2021, 5.33 million shares of common stock were issued (approximately $350 million). In 2022, 4.30 million shares of common stock were issued (approximately $300 million). As of Dec. 31, 2022, approximately $150 million remained available for sale under the ATM program.

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Capital Stock — Preferred stock authorized/outstanding:


	Preferred Stock Authorized (Shares)	Par Value of Preferred Stock		Preferred Stock Outstanding (Shares) 2022 and 2021
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, 2022						Common Stock Outstanding (Shares) as of Dec. 31, 2021
1,000,000,000						$	2.50					549,578,018						544,025,269

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, 2022:


	Equity to Total Capitalization Ratio Required Range				Equity to Total Capitalization Ratio Actual
	Low		High		2022
NSP-Minnesota	47.2	%	57.6	%	52.3	%
NSP-Wisconsin	52.5		N/A		52.8
SPS (a)	45.0		55.0		54.3

(a) Excludes short-term debt.


(Amounts in Millions)	Unrestricted Retained Earnings		Total Capitalization		Limit on Total Capitalization
NSP-Minnesota	$	1,446	$	14,984	$	16,140
NSP-Wisconsin (a)	11		2,280		N/A
SPS (b)	540		7,094		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, 2022:


(Millions of Dollars)	Long-Term Debt			Short-Term Debt
NSP-Minnesota	52.8% of total capitalization		(a)	$	2,400	(a)
NSP-Wisconsin	$	50		150
SPS	—			600
PSCo	1,300			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.


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, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	3,542	$	1,814	$	53	$	5,409
C&I	5,807		998		32		6,837
Other	148		—		10		158
Total retail	9,497		2,812		95		12,404
Wholesale	1,354		—		—		1,354
Transmission	675		—		—		675
Other	97		178		—		275
Total revenue from contracts with customers	11,623		2,990		95		14,708
Alternative revenue and other	500		90		12		602
Total revenues	$	12,123	$	3,080	$	107	$	15,310


	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

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7. Income Taxes

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:


	2022		2021 (a)		2020 (a)
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	4.9		5.0		4.9
(Decreases) increases in tax from:
Wind PTCs (b)	(27.4)		(23.4)		(15.7)
Plant regulatory differences (c)	(5.5)		(6.2)		(7.6)
Other tax credits, net NOL & tax credit allowances	(1.3)		(1.1)		(1.2)
NOL Carryback	—		—		(0.9)
Other, net	(0.1)		0.1		(0.9)
Effective income tax rate	(8.4)	%	(4.6)	%	(0.4)	%

(a)Prior period amounts have been restated to conform with current year presentation.

(b)Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.

(c)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 taxes are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

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


(Millions of Dollars)	2022		2021		2020
Current federal tax expense (benefit)	$	1	$	15	$	(13)
Current state tax expense (benefit)	3		(2)		2
Current change in unrecognized tax expense	5		1		18
Deferred federal tax benefit	(239)		(183)		(89)
Deferred state tax expense	96		99		91
Deferred change in unrecognized tax expense (benefit)	3		5		(10)
Deferred ITCs	(4)		(5)		(5)
Total income tax benefit	$	(135)	$	(70)	$	(6)

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


(Millions of Dollars)	2022		2021		2020
Deferred tax (benefit) expense excluding items below	$	(138)	$	148	$	237
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	8		(221)		(247)
Tax (benefit) expense allocated to other comprehensive income and other	(10)		(6)		2
Deferred tax benefit	$	(140)	$	(79)	$	(8)

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


(Millions of Dollars)	2022		2021 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	6,442	$	6,231
Regulatory assets	508		560
Operating lease assets	325		351
Deferred fuel costs	222		262
Pension expense	159		175
Other	92		88
Total deferred tax liabilities	$	7,748	$	7,667

Deferred tax assets:
Tax credit carryforward	$	1,679	$	1,261
Regulatory liabilities	742		742
Operating lease liabilities	325		351
Other employee benefits	102		119
NOL carryforward	57		247
NOL and tax credit valuation allowances	(62)		(64)
Deferred ITCs	14		15
Other	135		102
Total deferred tax assets	$	2,992	$	2,773
Net deferred tax liability	$	4,756	$	4,894

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

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)	2022		2021
Federal NOL carryforward	$	20	$	765
Federal tax credit carryforwards	1,593		1,172
State NOL carryforwards	1,022		1,648
Valuation allowances for state NOL carryforwards	(3)		(3)
State tax credit carryforwards, net of federal detriment (a)	85		89
Valuation allowances for state credit carryforwards, net of federal benefit (b)	(62)		(64)

(a)State tax credit carryforwards are net of federal detriment of $23 million and $24 million as of Dec. 31, 2022 and 2021.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $16 million and $17 million as of Dec. 31, 2022 and 2021.

Federal carryforward periods expire starting 2032 and state carryforward periods expire starting 2022.

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.

Unrecognized Tax Benefits

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


Tax Year(s)						Expiration
2014 - 2016						March 2024
2019						October 2023

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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.

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, 2022, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:


State	Tax Year(s)	Expiration
Colorado	2014 - 2016	March 2025
Colorado	2018	September 2023
Minnesota	2014 - 2016	September 2024
Minnesota	2018	June 2023
Texas	2016	May 2023
Texas	2017	July 2025
Texas	2018	November 2023
Wisconsin	2016 - 2017	April 2023
Wisconsin	2018	October 2023

In 2020, Minnesota began an audit of tax years 2015-2018. In 2022, the state of Minnesota issued its audit report without any material adjustments.
In 2021, Texas began an audit of tax years 2016-2019. As of Dec. 31, 2022, no material adjustments have been proposed.
In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec. 31, 2022, no material adjustments have been proposed.
No other state income tax audits are in progress for its major operating jurisdictions as of Dec. 31, 2022.

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, 2022		Dec. 31, 2021
Unrecognized tax benefit — Permanent tax positions	$	55	$	47
Unrecognized tax benefit — Temporary tax positions	12		11
Total unrecognized tax benefit	$	67	$	58

Changes in unrecognized tax benefits:


(Millions of Dollars)	2022		2021		2020
Balance at Jan. 1	$	58	$	52	$	44
Additions based on tax positions related to the current year	7		5		9
Reductions based on tax positions related to the current year	—		—		(2)
Additions for tax positions of prior years	6		2		35
Reductions for tax positions of prior years	(1)		(1)		(34)
Reductions for tax positions related to settlements with taxing authorities	(1)		—		—
Reductions for tax positions related to statute of limitations	(2)		—		—
Balance at Dec. 31	$	67	$	58	$	52

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


(Millions of Dollars)						Dec. 31, 2022						Dec. 31, 2021
NOL and tax credit carryforwards						$	(40)					$	(36)

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 $40 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)	2022		2021		2020
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(3)	$	(3)	$	—
Interest expense related to unrecognized tax benefits	(1)		—		(3)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(4)	$	(3)	$	(3)

No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2022, 2021 or 2020.


8. Share-Based Compensation

Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 7.0 million equity shares under an incentive plan (the Amended and Restated 2015 Omnibus Incentive Plan).

Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the 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 time-based equity shares subject only to service conditions were granted annually in 2022, 2021 and 2020.

The performance conditions for a portion of the awards granted from 2020 to 2022 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:


(Units in Thousands)	2022		2021		2020
Granted units	395		421		411
Weighted average grant date fair value	$	68.43	$	66.03	$	62.92

Equity awards vested:


(Units in Thousands, Fair Value in Millions)	2022		2021		2020
Vested Units	319		392		442
Total Fair Value	$	22	$	27	$	29

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Changes in the nonvested portion of equity award units:


(Units in Thousands)	Units	Weighted Average Grant Date Fair Value
Nonvested Units at Jan. 1, 2022	695	$	64.59
Granted	395	68.43
Forfeited	(96)	65.53
Vested	(319)	63.03
Dividend equivalents	33	65.40
Nonvested Units at Dec. 31, 2022	708	67.35

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)	2022		2021		2020
Granted units	29		31		33
Weighted average grant date fair value	$	71.97	$	68.15	$	61.61

Changes in stock equivalent units:


(Units in Thousands)	Units	Weighted Average Grant Date Fair Value
Stock equivalent units at Jan. 1, 2022	604	$	39.27
Granted	29	71.97
Units distributed	(52)	38.16
Dividend equivalents	16	67.79
Stock equivalent units at Dec. 31, 2022	597	41.75

Liability Awards — Xcel Energy’s Board of Directors has granted TSR liability awards under the 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%.

Liability awards granted:


(In Thousands)						2022						2021						2020
Awards granted						165						221						212

Liability awards settled:


(Units In Thousands, Settlement Amount in Millions)	2022		2021		2020
Awards settled	411		446		476
Settlement amount (cash, common stock and deferred amounts)	$	27	$	27	$	33

TSR liability awards of $21 million were settled in cash in 2022.

Share-Based Compensation Expense — Award settlement determination (permitting cash or share settlement) is made by Xcel Energy, not the participants. Equity 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 are accounted for as liabilities, as historically they are partially settled in cash. 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)	2022		2021		2020
Cost for share-based awards (a)	$	36	$	31	$	73
Tax benefit recognized in income	9		8		19

(a)Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) amounted to $20 million in 2022.

There was approximately $37 million and $28 million as of Dec. 31, 2022 and 2021, respectively, 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 1.8 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 — 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)	2022	2021	2020
Basic	547	539	527
Diluted (a)	547	540	528

(a)Diluted common shares outstanding included common stock equivalents of 0.3 million, 0.3 million and 1.1 million shares for 2022, 2021 and 2020, 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 hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.

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 actively traded instruments with observable actual trading prices.
Level 2 — Pricing inputs are other than actual trading 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 include those valued with models requiring significant judgment or estimation.

Specific valuation methods include:

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 funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds 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 contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from 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 values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.

FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.

Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.

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 billion and $1.3 billion as of Dec. 31, 2022 and 2021, respectively, and unrealized losses were $90 million and $7 million as of Dec. 31, 2022 and 2021, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:


	Dec. 31, 2022
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	29	$	29	$	—	$	—	$	—	$	29
Commingled funds	803		—		—		—		1,178		1,178
Debt securities	738		—		669		6		—		675
Equity securities	406		999		1		—		—		1,000
Total	$	1,976	$	1,028	$	670	$	6	$	1,178	$	2,882

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity method investments and $133 million of rabbi trust assets and other miscellaneous investments.


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

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

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For the years ended Dec. 31, 2022 and 2021, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2022:


	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	$	6	$	204	$	250	$	215	$	675

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future distributions of deferred compensation plan. The fair value of assets held in the rabbi trusts were $80 million and $109 million at Dec. 31, 2022 and 2021, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Derivative Activities and 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, and utility commodity prices.

Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.

As of Dec. 31, 2022, accumulated other comprehensive loss related to interest rate derivatives included $2 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, 2022, Xcel Energy had unsettled interest swaps outstanding with a notional amount of $40 million. These interest rate derivatives were designated as cash flow hedges, with changes in fair value recorded to other comprehensive income.

See Note 13 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.

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

Derivative instruments entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.

Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.

The most significant derivative positions outstanding at December 31, 2022 and 2021 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.

Higher congestion costs in recent years have led to an increase in the fair value of FTRs. Settlements of FTRs are shared with electric customers through fuel and purchased energy cost-recovery mechanisms.

When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically 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, 2022, Xcel Energy had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards, options and FTRs:


(Amounts in Millions) (a)(b)	Dec. 31, 2022	Dec. 31, 2021
MWh of electricity	61	80
MMBtu of natural gas	131	156

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented 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.

As of Dec. 31, 2022, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $75 million or 37% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

Four of the ten most significant counterparties, comprising $63 million or 32% of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.

Two of these significant counterparties, comprising $62 million or 31% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

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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, 2022 and 2021, there were $4 million and $3 million, respectively, of derivative liabilities 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 other financing arrangements related to payment terms or other covenants.

As of Dec. 31, 2022 and 2021, there were approximately $76 million and $64 million of derivative liabilities with such underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.

Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2022 and 2021.

Recurring Derivative Fair Value Measurements

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, 2022
Derivatives designated as cash flow hedges
Interest rate	$	22	$	—
Total	$	22	$	—
Other derivative instruments
Electric commodity	$	—	$	(10)
Natural gas commodity	—		(16)
Total	$	—	$	(26)

Year Ended Dec. 31, 2021
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)


	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, 2022
Derivatives designated as cash flow hedges
Interest rate	$	7	(a)	$	—		$	—
Total	$	7		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	25	(b)
Electric commodity	—			3		(c)	—
Natural gas commodity	—			10		(d)	(27)		(d)(e)
Total	$	—		$	13		$	(2)

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)(e)
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)(e)
Total	$	—		$	7		$	(14)

(a)Recorded to interest charges.

(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.

(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. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.

(d)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.

(e)Relates primarily to option premium amortization.

Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2022, 2021 and 2020.

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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:


	Dec. 31, 2022														Dec. 31, 2021
	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	$	32	$	259	$	33	$	324	$	(242)		$	82		$	22		$	137	$	21	$	180	$	(134)	$	46
Electric commodity	—		—		177		177		(2)			175			—			—		57		57		(1)		56
Natural gas commodity	—		19		—		19		—			19			—			18		—		18		—		18
Total current derivative assets	$	32	$	278	$	210	$	520	$	(244)		276			$	22		$	155	$	78	$	255	$	(135)	120
PPAs (b)												3														3
Current derivative instruments												$	279													$	123
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	34	$	71	$	74	$	179	$	(89)		$	90		$	16		$	63	$	89	$	168	$	(107)	$	61
Total noncurrent derivative assets	$	34	$	71	$	74	$	179	$	(89)		90			$	16		$	63	$	89	$	168	$	(107)	61
PPAs (b)												3														6
Noncurrent derivative instruments												$	93													$	67


	Dec. 31, 2022														Dec. 31, 2021
	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
Derivatives designated as cash flow hedges:
Interest rate	$	—	$	1	$	—	$	1	$	—		$	1		$	—		$	—	$	—	$	—	$	—	$	—
Other derivative instruments:
Commodity trading	$	29	$	297	$	6	$	332	$	(287)		$	45		$	19		$	148	$	20	$	187	$	(143)	$	44
Electric commodity	—		—		2		2		(2)			—			—			—		1		1		(1)		—
Natural gas commodity	—		13		—		13		—			13			—			8		—		8		—		8
Total current derivative liabilities	$	29	$	311	$	8	$	348	$	(289)		59			$	19		$	156	$	21	$	196	$	(144)	52
PPAs (b)												17														17
Current derivative instruments												$	76													$	69
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	43	$	97	$	41	$	181	$	(98)		$	83		$	18		$	48	$	127	$	193	$	(128)	$	65
Total noncurrent derivative liabilities	$	43	$	97	$	41	$	181	$	(98)		83			$	18		$	48	$	127	$	193	$	(128)	65
PPAs (b)												30														40
Noncurrent derivative instruments												$	113													$	105

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $53 million and $30 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are 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)	2022		2021		2020
Balance at Jan. 1	$	19	$	(49)	$	4
Purchases (a)	406		65		51
Settlements (a)	(350)		(158)		(73)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (b)	151		49		(39)
Net gains recognized as regulatory assets and liabilities (a)	10		112		8
Balance at Dec. 31	$	236	$	19	$	(49)

(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.

(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.

Fair Value of Long-Term Debt

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


	2022				2021
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	23,964	$	20,897	$	22,380	$	25,232

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2022 and 2021, 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 4.89, 2.03 and 1.89% in 2022, 2021, and 2020, 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, 2022 and 2021 were $11 million and $43 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $17 million in 2022 and $4 million in 2021.

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 the long-term projected return levels from investment experts.

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

Investment returns in 2022 were below the assumed level of 6.49%.
Investment returns in 2021 were above the assumed level of 6.49%.
Investment returns in 2020 were above the assumed level of 6.87%.
In 2023, expected investment-return assumption is 6.93%.

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, 2022 (a)										Dec. 31, 2021 (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	$	129	$	—	$	—	$	—	$	129	$	133	$	—	$	—	$	—	$	133
Commingled funds	935		—		—		882		1,817		1,324		—		—		1,143		2,467
Debt securities	—		682		3		—		685		—		959		5		—		964
Equity securities	47		—		—		—		47		67		—		—		—		67
Other	—		7		—		—		7		—		7		—		32		39
Total	$	1,111	$	689	$	3	$	882	$	2,685	$	1,524	$	966	$	5	$	1,175	$	3,670

(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, 2022 (a)										Dec. 31, 2021 (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	$	31	$	—	$	—	$	—	$	31	$	28	$	—	$	—	$	—	$	28
Insurance contracts	—		41		—		—		41		—		52		—		—		52
Commingled funds	54		—		—		63		117		64		—		—		77		141
Debt securities	—		175		1		—		176		—		218		1		—		219
Other	—		(1)		—		—		(1)		—		2		—		—		2
Total	$	85	$	215	$	1	$	63	$	364	$	92	$	272	$	1	$	77	$	442

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

Immaterial assets were transferred in or out of Level 3 for 2022. No assets were transferred in or out of Level 3 for 2021.

Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2021 to Dec. 31, 2022, 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)	2022		2021		2022		2021
Change in Benefit Obligation:
Obligation at Jan. 1	$	3,718	$	3,964	$	511	$	574
Service cost	97		104		2		2
Interest cost	110		104		15		15
Plan amendments	1		5		—		—
Actuarial gain	(703)		(94)		(85)		(41)
Plan participants’ contributions	—		—		8		8
Medicare subsidy reimbursements	—		—		2		2
Benefit payments (a)	(352)		(365)		(48)		(49)
Obligation at Dec. 31	$	2,871	$	3,718	$	405	$	511
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	3,670	$	3,599	$	442	$	452
Actual return on plan assets	(683)		305		(51)		16
Employer contributions	50		131		13		15
Plan participants’ contributions	—		—		8		8
Benefit payments	(352)		(365)		(48)		(49)
Fair value of plan assets at Dec. 31	$	2,685	$	3,670	$	364	$	442
Funded status of plans at Dec. 31	$	(186)	$	(48)	$	(41)	$	(69)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets	$	15	$	19	$	33	$	33
Current liabilities	—		—		(2)		(4)
Noncurrent liabilities	(201)		(67)		(72)		(98)
Net amounts recognized	$	(186)	$	(48)	$	(41)	$	(69)

(a)Includes approximately $195 million in 2022 and $197 million in 2021 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:	2022		2021		2022		2021
Discount rate for year-end valuation	5.80	%	3.08	%	5.80	%	3.09	%
Expected average long-term increase in compensation level	4.25		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		6.50	%	5.30	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.50	%	4.90	%
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		7		4

Accumulated benefit obligation for the pension plan was $2,672 million and $3,469 million as of Dec. 31, 2022 and 2021, 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)	2022			2021			2020			2022			2021			2020
Service cost	$	97		$	104		$	95		$	2		$	2		$	1
Interest cost	110			104			125			15			15			18
Expected return on plan assets	(208)			(206)			(208)			(18)			(18)			(19)
Amortization of prior service credit	(1)			(1)			(4)			(6)			(8)			(8)
Amortization of net loss	75			107			100			2			5			4
Settlement charge (a)	71			59			—			—			—			—
Net periodic pension cost (credit)	144			167			108			(5)			(4)			(4)
Effects of regulation	(30)			(46)			9			3			2			3
Net benefit cost (credit) recognized for financial reporting	$	114		$	121		$	117		$	(2)		$	(2)		$	(1)
Significant Assumptions Used to Measure Costs:
Discount rate	3.08		%	2.71		%	3.49		%	3.09		%	2.65		%	3.47		%
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			6.49			6.87			4.10			4.10			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 2022 and 2021, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $71 million and $59 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $9 million and $7 million was recorded in the consolidated statements of income in 2022 and 2021, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.


	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2022		2021		2022		2021
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	1,021	$	978	$	63	$	81
Prior service credit	(7)		(9)		(1)		(7)
Total	$	1,014	$	969	$	62	$	74
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	$	21	$	74	$	—	$	—
Noncurrent regulatory assets	943		846		78		90
Current regulatory liabilities	—		—		(1)		(1)
Noncurrent regulatory liabilities	—		—		(20)		(19)
Deferred income taxes	14		13		1		1
Net-of-tax accumulated other comprehensive income	36		36		4		3
Total	$	1,014	$	969	$	62	$	74


Measurement date						Dec. 31, 2022						Dec. 31, 2021						Dec. 31, 2022						Dec. 31, 2021

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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 2020 - 2023 to meet minimum funding requirements.

Voluntary and required pension funding contributions:

$50 million in January 2023.
$50 million in 2022.
$131 million in 2021.
$150 million in 2020.

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:

$12 million expected during 2023.
$13 million during 2022.
$15 million during 2021.
$11 million during 2020.

Targeted asset allocations:


	Pension Benefits				Postretirement Benefits
	2022		2021		2022		2021
Domestic and international equity securities	33	%	33	%	16	%	15	%
Long-duration fixed income securities	38		37		—		—
Short-to-intermediate fixed income securities	9		11		71		71
Alternative investments	18		17		12		8
Cash	2		2		1		6
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 — There were no significant plan amendments made in 2022 or 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
2023	$	283	$	42	$	2	$	40
2024	249		41		2		39
2025	249		40		2		38
2026	246		39		2		37
2027	243		37		2		35
2028 - 2032	1,162		167		12		155

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $46 million in 2022, $43 million in 2021 and $42 million in 2020.

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.). The Court issued a ruling on June 30, 2022 granting plaintiffs’ class certification. Defendants will work together to prepare and file a petition appealing the class certification ruling to the Seventh Circuit. Xcel Energy has concluded that a loss is remote for the remaining lawsuit.

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Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion to dismiss CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In April 2022, CORE filed a supplement to include the January 2022 outage and damages related to this event. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million. Also in February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. PSCo continues to believe CORE's claims are without merit and disputes CORE’s right to withdraw.

Rate Matters and Other

Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

Sherco — In 2018, NSP-Minnesota and 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 fuel clause adjustment.

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers.

In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.

In January 2021, the Minnesota Office of the Attorney General and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.

A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote.

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%.

The FERC subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions.

The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial.

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

In 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in 2018. The FERC subsequently issued a tolling order granting a rehearing for further consideration. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In 2020, SPS filed a petition for review of the FERC’s 2018 orders at the D.C. Circuit. In February 2022, FERC issued an order rejecting SPS’ request for hearing. SPS has appealed that order. That appeal has been combined with SPS’ prior appeal.

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, 2022, the full-year net capacity factor exceeded the guaranteed level, resulting in no refund liability for 2022.

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.

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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 9 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 applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.

As of Dec. 31, 2022, Xcel Energy had eight regulated ash units in operation.

PSCo is currently exploring an agreement with a third party that would excavate and process ash for beneficial use (at two sites) and perform restoration at one site at a cost of approximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.

Investigation and feasibility studies for additional corrective action related to offsite groundwater are ongoing (three sites). While the results are uncertain, additional costs are estimated to be up to $35 million. A liability has been recorded for the portion estimable/probable and are expected to be fully recoverable through regulatory mechanisms.

Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.

Estimated capital expenditures of approximately $45 million may be required for NSP-Minnesota to comply with the requirements pending approval of mitigation plans from the MPCA. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.

Environmental Requirements — Air

Reasonable Progress Rule and BART — 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 which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.

In 2017, the EPA adopted a final BART rule for Texas. Under that rule, Harrington Units 1, 2, and 3 and Tolk Units 1 and 2 participate in intrastate SO2 budget and trading program. The rule also implemented participation in a federal ozone season NOx budget and trading program, named the Cross State Air Pollution Rule. The EPA is reconsidering this rule.

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.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $2.9 billion and $3.3 billion for 2022 and 2021, respectively.

Xcel Energy’s AROs were as follows:


(Millions of Dollars)	Jan. 1, 2022		Amounts Incurred (a)		Accretion		Cash Flow Revisions (b)		Dec. 31, 2022
Electric
Nuclear	$	2,056	$	—	$	104	$	—	$	2,160
Wind	478		25		19		(8)		514
Steam, hydro and other production	288		34		12		14		348
Distribution	47		—		1		—		48
Natural gas
Transmission and distribution	271		—		12		23		306
Miscellaneous	8		—		—		(7)		1
Common
Miscellaneous	1		—		—		—		1
Non-utility
Miscellaneous	2		—		—		—		2
Total liability	$	3,151	$	59	$	148	$	22	$	3,380

(a)Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota (Dakota Range and Rock Aetna) and steam production pond remediation costs for PSCo.

(b)In 2022, 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.

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(Millions of Dollars)	Jan. 1, 2021		Amounts Incurred (a)		Accretion		Cash Flow Revisions (b)		Dec. 31, 2021
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.

Indeterminate AROs — Outside of the recorded asbestos 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, 2022. 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 $13.7 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.2 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 $20 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 $12 million for business interruption insurance and $32 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 50 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 to 2040. 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 authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101.

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. The MPUC reaffirmed a 60-year DECON scenario, where Monticello continues operations under a 10-year license extension (approved in August 2022). NRC approval of the extension is pending.

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. The 2020 nuclear decommissioning filing was approved by the MPUC and became effective in 2022.

Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $2.9 billion and $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2022, and 2021, respectively.

See Note 10 to the consolidated financial statements for additional discussion.

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.

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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 4.1%). 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, 2022		Dec. 31, 2021
PPAs	$	1,669	$	1,656
Other	244		225
Gross operating lease ROU assets	1,913		1,881
Accumulated amortization	(709)		(590)
Net operating lease ROU assets	$	1,204	$	1,291

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.

Finance lease ROU assets:


(Millions of Dollars)	Dec. 31, 2022		Dec. 31, 2021
Gas storage facilities	$	160	$	201
Gas pipeline	21		21
Gross finance lease ROU assets	181		222
Accumulated amortization	(64)		(97)
Net finance lease ROU assets	$	117	$	125

Components of lease expense:


(Millions of Dollars)	2022		2021		2020
Operating leases
PPA capacity payments	$	241	$	251	$	238
Other operating leases (a)	39		36		26
Total operating lease expense (b)	$	280	$	287	$	264
Finance leases
Amortization of ROU assets	$	4	$	7	$	7
Interest expense on lease liability	16		17		18
Total finance lease expense	$	20	$	24	$	25

(a)Includes short-term lease expense of $6 million for 2022 and $5 million for 2021 and 2020.

(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, 2022:


(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (c)
2023	$	231	$	33	$	264	$	10
2024	238		28		266		10
2025	217		23		240		10
2026	161		18		179		9
2027	90		18		108		8
Thereafter	326		74		400		181
Total minimum obligation	1,263		194		1,457		228
Interest component of obligation	(170)		(32)		(202)		(162)
Present value of minimum obligation	$	1,093	162		1,255		66
Less current portion					(217)		(2)
Noncurrent operating and finance lease liabilities					$	1,038	$	64

Weighted-average remaining lease term in years					7.9		37.8

(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 2033.

(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 $182 million, $149 million and $112 million in 2022, 2021 and 2020, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $75 million, $69 million and $75 million in 2022, 2021 and 2020, 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, 2022, 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)
2023	$	77	$	50
2024	72		45
2025	29		51
2026	10		48
2027	7		55
Thereafter	3		28
Total	$	198	$	277

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

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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 2023 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, 2022:


(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas supply and transportation
2023	$	628	$	144	$	684	$	316
2024	343		112		8		290
2025	90		158		1		276
2026	53		37		—		276
2027	55		155		—		225
Thereafter	2		194		—		607
Total	$	1,171	$	800	$	693	$	1,990

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, however it 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.

The utility subsidiaries had approximately 3,961 MW and 4,062 MW of capacity under these long-term PPAs at Dec. 31, 2022 and 2021, respectively, 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 2024 and December 2027, respectively. 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 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 with affordable rental housing activities that qualify for low-income housing tax credits.

Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities, consolidate these limited partnerships in their consolidated financial statements.

Amounts reflected in Xcel Energy’s consolidated balance sheets for these investments include $44 million of assets and $35 million of liabilities at Dec. 31, 2022, and $45 million of assets and $35 million of liabilities at Dec. 31, 2021.

Other

Technology Agreements — Xcel Energy has several contracts for information technology services that extend through 2027. The contracts are cancelable, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $181 million, $103 million and $110 million associated with these vendors in 2022, 2021 and 2020, respectively.

Committed minimum payments under these obligations as follows:


(Millions of Dollars)	Minimum Payments
2023	$	24
2024	13
2025	12
2026	11
2027	10
Thereafter	—

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, 2022 and 2021, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $62 million and $60 million at Dec. 31, 2022 and 2021 respectively.

Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.

Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

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13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:


	2022
(Millions of Dollars)	Gains and Losses on Interest Rate Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(75)		$	(48)		$	(123)
Other comprehensive gain before reclassifications	16			5			21
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	5		(a)	—			5
Amortization of net actuarial loss	—			4		(b)	4
Net current period other comprehensive income	21			9			30
Accumulated other comprehensive loss at Dec. 31	$	(54)		$	(39)		$	(93)

(a)Included in interest charges.

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


	2021
(Millions of Dollars)	Gains and Losses on Interest Rate Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(85)		$	(56)		$	(141)
Other comprehensive gain before reclassifications	4			—			4
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges	6		(a)	—			6
Amortization of net actuarial loss	—			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.


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 $219 million and $208 million as of Dec. 31, 2022 and 2021, respectively, included in the natural gas utility and all other segments.

Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment.

Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

Table of Contents

Xcel Energy’s segment information:


(Millions of Dollars)	2022		2021		2020
Regulated Electric
Operating revenues — external	$	12,123	$	11,205	$	9,802
Intersegment revenue	2		2		2
Total revenues	$	12,125	$	11,207	$	9,804
Depreciation and amortization	2,122		1,855		1,673
Interest charges and financing costs	636		568		534
Income tax (benefit) expense	(162)		(96)		1
Net income	1,631		1,478		1,407
Regulated Natural Gas
Operating revenues — external	$	3,080	$	2,132	$	1,636
Intersegment revenue	2		2		1
Total revenues	$	3,082	$	2,134	$	1,637
Depreciation and amortization	276		254		252
Interest charges and financing costs	86		75		71
Income tax expense	68		54		17
Net income	264		231		190
All Other
Total revenues	$	107	$	94	$	88
Depreciation and amortization	15		12		23
Interest charges and financing costs	203		173		193
Income tax benefit	(41)		(28)		(24)
Net loss	(159)		(112)		(124)

Consolidated Total
Total revenues	$	15,314	$	13,435	$	11,529
Reconciling eliminations	(4)		(4)		(3)
Total operating revenues	$	15,310	$	13,431	$	11,526
Depreciation and amortization	2,413		2,121		1,948
Interest charges and financing costs	925		816		798
Income tax (benefit) expense	(135)		(70)		(6)
Net income	1,736		1,597		1,473

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