xel-20240331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2024


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-3034


Xcel Energy Inc.
(Exact Name of Registrant as Specified in its Charter)

Minnesota

41-0448030

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification No.)

414 Nicollet Mall

Minneapolis

Minnesota

55401

(Address of Principal Executive Offices)

(Zip Code)


(612)			330-5500
(Registrant’s Telephone Number, Including Area Code)


N/A
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $2.50 par value

XEL

Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class						Outstanding at April 22, 2024
Common Stock, $2.50 par value						555,639,439 shares

TABLE OF CONTENTS


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	5
	Consolidated Statements of Income	5
	Consolidated Statements of Comprehensive Income	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Common Stockholders’ Equity	9
	Notes to Consolidated Financial Statements	10
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	31
Item 4 —	Controls and Procedures	32

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	32
Item 1A —	Risk Factors	32
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 5 —	Other Information	32
Item 6 —	Exhibits	33

SIGNATURES		34

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available in various filings with the SEC. This report should be read in its entirety.

Definitions of Abbreviations


Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime			e prime inc.
NSP-Minnesota			Northern States Power Company, a Minnesota corporation
NSP System			The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin			Northern States Power Company, a Wisconsin corporation
PSCo			Public Service Company of Colorado
SPS			Southwestern Public Service Company
Utility subsidiaries			NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCO			WYCO Development, LLC
Xcel Energy			Xcel Energy Inc. and its subsidiaries


Federal and State Regulatory Agencies
CPUC			Colorado Public Utilities Commission
D.C. Circuit			United States Court of Appeals for the District of Columbia Circuit
DOC			Minnesota Department of Commerce
DOE			United States Department of Energy
EPA			United States Environmental Protection Agency
FERC			Federal Energy Regulatory Commission


MPUC			Minnesota Public Utilities Commission
MPSC			Michigan Public Service Commission
NDPSC			North Dakota Public Service Commission
NMPRC			New Mexico Public Regulation Commission
NRC			Nuclear Regulatory Commission
OAG			Minnesota Office of Attorney General
PSCW			Public Service Commission of Wisconsin
PUCT			Public Utility Commission of Texas
SEC			Securities and Exchange Commission
SDPUC			South Dakota Public Utilities Commission


Other
AFUDC			Allowance for funds used during construction

ALJ			Administrative Law Judge

ATM			At-the-market

BART			Best available retrofit technology
C&I			Commercial and Industrial
CCR			Coal combustion residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD			Cooling degree-days


CEO			Chief executive officer
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFO			Chief financial officer
CORE			CORE Electric Cooperative
CPCN			Certificate of Public Convenience and Necessity
CSPV			Crystalline Silicon Photovoltaic
CUB			Citizens Utility Board
DRIP			Dividend Reinvestment and Stock Purchase Program
EPS			Earnings per share
ETR			Effective tax rate

FTR			Financial transmission right

GAAP			United States generally accepted accounting principles
GCA			Gas cost adjustment
GE			General Electric Company
HDD			Heating degree-days
IPP			Independent power producing entity
IRP			Integrated Resource Plan


LLC			Limited liability company
LP&L			Lubbock Power and Light
MGP			Manufactured gas plant
MPH			Miles per hour
MISO			Midcontinent Independent System Operator, Inc.
NAV			Net asset value

NOx			Nitrogen Oxides
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff

PFAS			Per- and Polyfluoroalkyl Substances
PIM			Performance incentive mechanism
PPA			Power purchase agreement
PTC			Production tax credit
RFP			Request for proposal
ROE			Return on equity
RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.

TEP			Transportation electrification plan

THI			Temperature-humidity index


VaR			Value at Risk
WACC			Weighted average cost of capital


Measurements
MW			Megawatts


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2024 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2023 and subsequent filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.

Table of Contents

PART I — FINANCIAL INFORMATION


ITEM 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in millions, except per share data)


	Three Months Ended March 31
	2024		2023
Operating revenues
Electric	$	2,685	$	2,763
Natural gas	941		1,288
Other	23		29
Total operating revenues	3,649		4,080

Operating expenses
Electric fuel and purchased power	948		1,117
Cost of natural gas sold and transported	483		844
Cost of sales — other	8		12
Operating and maintenance expenses	605		650
Conservation and demand side management expenses	97		76
Depreciation and amortization	658		624
Taxes (other than income taxes)	171		184

Total operating expenses	2,970		3,507

Operating income	679		573

Other income, net	14		5
Earnings from equity method investments	8		11
Allowance for funds used during construction — equity	37		19

Interest charges and financing costs
Interest charges — includes other financing costs	291		253
Allowance for funds used during construction — debt	(14)		(10)
Total interest charges and financing costs	277		243

Income before income taxes	461		365
Income tax benefit	(27)		(53)
Net income	$	488	$	418

Weighted average common shares outstanding:
Basic	556		551
Diluted	556		551

Earnings per average common share:
Basic	$	0.88	$	0.76
Diluted	0.88		0.76

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in millions)


	Three Months Ended March 31
	2024		2023
Net income	$	488	$	418
Other comprehensive income



Derivative instruments:
Net fair value increase (decrease), net of tax	22		(5)
Reclassification of losses to net income, net of tax	1		1

Total other comprehensive income (loss)	23		(4)
Total comprehensive income	$	511	$	414

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in millions)


	Three Months Ended March 31
	2024		2023
Operating activities
Net income	$	488	$	418
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	664		631
Nuclear fuel amortization	20		29
Deferred income taxes	154		(73)
Allowance for equity funds used during construction	(37)		(19)
Earnings from equity method investments	(8)		(11)
Dividends from equity method investments	9		9
Provision for bad debts	17		23
Share-based compensation expense	6		9
Changes in operating assets and liabilities:
Accounts receivable	78		50
Accrued unbilled revenues	73		329
Inventories	50		189
Other current assets	(65)		8
Accounts payable	(114)		(359)
Net regulatory assets and liabilities	81		345
Other current liabilities	(180)		63
Pension and other employee benefit obligations	(103)		(45)
Other, net	(83)		(59)
Net cash provided by operating activities	1,050		1,537

Investing activities
Capital/construction expenditures	(1,537)		(1,265)
Purchase of investment securities	(189)		(236)
Proceeds from the sale of investment securities	179		228
Other, net	(9)		(11)
Net cash used in investing activities	(1,556)		(1,284)

Financing activities
Repayments of short-term borrowings, net	(322)		266
Proceeds from issuances of long-term debt	1,478		—
Repayments of long-term debt, including reacquisition premiums	—		(250)
Proceeds from issuance of common stock	8		6
Dividends paid	(280)		(259)
Other, net	(6)		(13)
Net cash provided by (used in) financing activities	878		(250)

Net change in cash, cash equivalents and restricted cash	372		3
Cash, cash equivalents and restricted cash at beginning of period	129		111
Cash, cash equivalents and restricted cash at end of period	$	501	$	114

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(230)	$	(209)
Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers	131		(1)

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	452	$	449
Inventory transfers to property, plant and equipment	99		34
Operating lease right-of-use assets	—		47
Allowance for equity funds used during construction	37		19
Issuance of common stock for reinvested dividends and/or equity awards	15		21


See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in millions, except share and per share data


	March 31, 2024		Dec. 31, 2023
Assets
Current assets
Cash and cash equivalents	$	501	$	129
Accounts receivable, net	1,220		1,315
Accrued unbilled revenues	779		853
Inventories	623		711
Regulatory assets	647		611
Derivative instruments	86		104
Prepaid taxes	85		52
Prepayments and other	548		294
Total current assets	4,489		4,069

Property, plant and equipment, net	52,765		51,642

Other assets
Nuclear decommissioning fund and other investments	3,746		3,599
Regulatory assets	2,769		2,798
Derivative instruments	90		76
Operating lease right-of-use assets	1,164		1,217
Other	562		678
Total other assets	8,331		8,368
Total assets	$	65,585	$	64,079

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	552	$	552
Short-term debt	463		785
Accounts payable	1,461		1,668
Regulatory liabilities	557		528
Taxes accrued	638		557
Accrued interest	291		251
Dividends payable	304		289
Derivative instruments	45		74
Operating lease liabilities	228		226
Other	671		722
Total current liabilities	5,210		5,652

Deferred credits and other liabilities
Deferred income taxes	5,108		4,885
Deferred investment tax credits	58		60
Regulatory liabilities	5,990		5,827
Asset retirement obligations	3,255		3,218
Derivative instruments	90		86
Customer advances	159		167
Pension and employee benefit obligations	364		469
Operating lease liabilities	980		1,038
Other	134		148
Total deferred credits and other liabilities	16,138		15,898

Commitments and contingencies
Capitalization
Long-term debt	26,396		24,913
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 555,470,302 and 554,941,703 shares outstanding at March 31, 2024 and December 31, 2023, respectively	1,389		1,387
Additional paid in capital	8,481		8,465
Retained earnings	8,042		7,858
Accumulated other comprehensive loss	(71)		(94)
Total common stockholders’ equity	17,841		17,616
Total liabilities and equity	$	65,585	$	64,079

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

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


	Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
	Shares	Par Value		Additional Paid In Capital
Three Months Ended March 31, 2024 and 2023
Balance at Dec. 31, 2022	549,578,018	$	1,374	$	8,155	$	7,239	$	(93)	$	16,675
Net income						418				418
Other comprehensive loss								(4)		(4)
Dividends declared on common stock ($0.52 per share)						(286)				(286)
Issuances of common stock	644,174	2		16						18

Share-based compensation				(2)		(1)				(3)
Balance at March 31, 2023	550,222,192	$	1,376	$	8,169	$	7,370	$	(97)	$	16,818

Balance at Dec. 31, 2023	554,941,703	$	1,387	$	8,465	$	7,858	$	(94)	$	17,616
Net income						488				488
Other comprehensive income								23		23
Dividends declared on common stock ($0.5475 per share)						(304)				(304)
Issuances of common stock	528,599	2		10						12

Share-based compensation				6						6
Balance at March 31, 2024	555,470,302	$	1,389	$	8,481	$	8,042	$	(71)	$	17,841























See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of March 31, 2024 and Dec. 31, 2023; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, cash flows and changes in stockholders’ equity for the three months ended March 31, 2024 and 2023.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2024, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2023 balance sheet information has been derived from the audited 2023 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023.

Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023, filed with the SEC on Feb. 21, 2024.

Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

Recently Issued

Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.

Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.

Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 greenhouse gas emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect implementation of the new guidance to have a material impact on the consolidated financial statements.


3. Selected Balance Sheet Data


(Millions of Dollars)	March 31, 2024		Dec. 31, 2023
Accounts receivable, net
Accounts receivable	$	1,339	$	1,443
Less allowance for bad debts	(119)		(128)
Accounts receivable, net	$	1,220	$	1,315


(Millions of Dollars)	March 31, 2024		Dec. 31, 2023
Inventories
Materials and supplies	$	384	$	377
Fuel	192		211
Natural gas	47		123
Total inventories	$	623	$	711


(Millions of Dollars)	March 31, 2024		Dec. 31, 2023
Property, plant and equipment, net
Electric plant	$	52,982	$	52,494
Natural gas plant	9,198		9,080
Common and other property	3,216		3,190
Plant to be retired (a)	1,996		2,055
Construction work in progress	3,773		2,873
Total property, plant and equipment	71,165		69,692
Less accumulated depreciation	(18,771)		(18,399)
Nuclear fuel	3,379		3,337
Less accumulated amortization	(3,008)		(2,988)
Property, plant and equipment, net	$	52,765	$	51,642

(a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. Amounts are presented net of accumulated depreciation.


4. Borrowings and Other Financing Instruments

Short-Term Borrowings

Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.

Table of Contents

Commercial paper and term loan borrowings outstanding for Xcel Energy:


(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2024			Year Ended Dec. 31, 2023
Borrowing limit	$	3,550		$	3,550
Amount outstanding at period end	463			785
Average amount outstanding	807			491
Maximum amount outstanding	1,314			1,241
Weighted average interest rate, computed on a daily basis	5.53		%	5.12		%
Weighted average interest rate at period end	5.49			5.52

Letters of Credit — Xcel Energy Inc. and its utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain obligations. There was $44 million of letters of credit outstanding under the credit facilities at both March 31, 2024 and Dec. 31, 2023. Amounts approximate their fair value and are subject to fees.

Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities equal to or greater than the commercial paper borrowing limits and cannot issue commercial paper exceeding available credit facility capacity. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

As of March 31, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	$	1,500	$	50	$	1,450
PSCo	700		298		402
NSP-Minnesota	700		15		685
SPS	500		145		355
NSP-Wisconsin	150		—		150
Total	$	3,550	$	508	$	3,042

(a)Expires in September 2027.

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

Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of March 31, 2024 and Dec. 31, 2023.

Bilateral Credit Agreement

In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of March 31, 2024, NSP-Minnesota had $65 million of outstanding letters of credit under the $75 million bilateral credit agreement.

Long-Term Borrowings and Other Financing Instruments

During the three months ended March 31, 2024, Xcel Energy Inc. and its utility subsidiaries issued the following:

•Xcel Energy Inc. issued $800 million of 5.50% Senior Unsecured Notes due March 15, 2034.

•NSP-Minnesota issued $700 million of 5.40% First Mortgage Bonds due March 15, 2054.

On April 4, 2024, PSCo issued $450 million of 5.35% First Mortgage Bonds due May 15, 2034 and $750 million of 5.75% First Mortgage Bonds due May 15, 2054.

ATM Equity Offering — In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, Xcel Energy Inc. issued 3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In the three months ended March 31, 2024, no shares were issued under the ATM program. As of March 31, 2024, approximately $2.3 billion remained available for sale under the ATM program.

Equity through DRIP and Benefits Program — Xcel Energy issued $17 million and $15 million of equity through the DRIP and benefits programs during the three months ended March 31, 2024 and 2023, respectively. The programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.


5. Revenues

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


	Three Months Ended March 31, 2024
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	859	$	568	$	10	$	1,437
C&I	1,276		274		9		1,559
Other	34		—		2		36
Total retail	2,169		842		21		3,032
Wholesale	173		—		—		173
Transmission	158		—		—		158
Other	19		59		—		78
Total revenue from contracts with customers	2,519		901		21		3,441
Alternative revenue and other	166		40		2		208
Total revenues	$	2,685	$	941	$	23	$	3,649

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	Three Months Ended March 31, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	875	$	789	$	13	$	1,677
C&I	1,352		423		12		1,787
Other	36		—		1		37
Total retail	2,263		1,212		26		3,501
Wholesale	224		—		—		224
Transmission	163		—		—		163
Other	9		48		—		57
Total revenue from contracts with customers	2,659		1,260		26		3,945
Alternative revenue and other	104		28		3		135
Total revenues	$	2,763	$	1,288	$	29	$	4,080


6. Income Taxes

Reconciliation between the statutory rate and ETR:


	Three Months Ended March 31
	2024		2023
Federal statutory rate	21.0	%	21.0	%
State tax (net of federal tax effect)	4.8		4.8
(Decreases) increases:
Wind PTCs (a)	(25.9)		(33.1)
Plant regulatory differences (b)	(5.6)		(5.5)
Other tax credits, net operating loss & tax credit allowances	(0.6)		(1.6)
Other (net)	0.4		(0.1)
Effective income tax rate	(5.9)	%	(14.5)	%

(a)Wind PTCs net of estimated transfer discounts are generally credited to customers (reduction to revenue) and do not materially impact net income.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.


7. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.

Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.

Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to time-based equity compensation awards.

Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock issued to employees is included in common shares outstanding when granted.

Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:

•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions have been satisfied by the end of the reporting period.

•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.

Common shares outstanding used in the basic and diluted EPS computation:


	Three Months Ended March 31
(Shares in Millions)	2024	2023
Basic	556	551
Diluted (a)	556	551

(a)Diluted common shares outstanding included common stock equivalents of 0.2 million for the three months ended March 31, 2024 and 2023.


8. 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.

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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 $1.3 billion and $1.2 billion as of March 31, 2024 and Dec. 31, 2023, respectively, and unrealized losses were $34 million and $29 million as of March 31, 2024 and Dec. 31, 2023, respectively.

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


	March 31, 2024
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	57	$	57	$	—	$	—	$	—	$	57
Commingled funds	718		—		—		—		1,042		1,042
Debt securities	804		—		781		9		—		790
Equity securities	511		1,457		2		—		—		1,459
Total	$	2,090	$	1,514	$	783	$	9	$	1,042	$	3,348

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $247 million of equity method investments and $151 million of rabbi trust assets and other miscellaneous investments.


	Dec. 31, 2023
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	41	$	41	$	—	$	—	$	—	$	41
Commingled funds	721		—		—		—		1,049		1,049
Debt securities	784		—		771		9		—		780
Equity securities	508		1,339		2		—		—		1,341
Total	$	2,054	$	1,380	$	773	$	9	$	1,049	$	3,211

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity investments in unconsolidated subsidiaries and $144 million of rabbi trust assets and other miscellaneous investments.

For the three months ended March 31, 2024 and 2023, there were no Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of March 31, 2024:


	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	$	276	$	257	$	251	$	790

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future distributions of a deferred compensation plan. The fair value of assets held in the rabbi trusts were $92 million and $88 million at March 31, 2024 and Dec. 31, 2023, 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.

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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 March 31, 2024, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of March 31, 2024, Xcel Energy had no unsettled interest swaps outstanding.

See Note 11 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.

Results of derivative instrument transactions 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 March 31, 2024 and Dec. 31, 2023 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.

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 March 31, 2024, 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)	March 31, 2024	Dec. 31, 2023
Megawatt hours of electricity	35	48
Million British thermal units of natural gas	78	84

(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 March 31, 2024, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $43 million, or 22%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

Five of the ten most significant counterparties, comprising $68 million, or 34%, 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.

One of these significant counterparties, comprising $54 million, or 27%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. Eight of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

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 March 31, 2024 and Dec. 31, 2023, there were $14 million and $12 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 March 31, 2024 and Dec. 31, 2023, there were approximately $86 million and $88 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 March 31, 2024 and Dec. 31, 2023.

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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
Three Months Ended March 31, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	29	$	—
Total	$	29	$	—
Other derivative instruments:
Electric commodity	$	—	$	(1)
Natural gas commodity	—		4
Total	$	—	$	3




















Three Months Ended March 31, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	(7)	$	—
Total	$	(7)	$	—
Other derivative instruments:
Electric commodity	$	—	$	(92)
Natural gas commodity	—		3
Total	$	—	$	(89)


	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
Three Months Ended March 31, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(8)	(b)
Electric commodity	—			12		(c)	—
Natural gas commodity	—			—			(14)		(d)(e)
Total	$	—		$	12		$	(22)











Three Months Ended March 31, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(1)	(b)
Electric commodity	—			82		(c)	—
Natural gas commodity	—			9		(d)	(19)		(d)(e)
Total	$	—		$	91		$	(20)

(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)Other than $2 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts 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 three months ended March 31, 2024 and 2023.

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


	March 31, 2024												Dec. 31, 2023
	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	$	9	$	45	$	30	$	84	$	(50)	$	34	$	8	$	51	$	32	$	91	$	(59)	$	32
Electric commodity	—		—		54		54		(4)		50		—		—		62		62		(7)		55
Natural gas commodity	—		—		—		—		—		—		—		14		—		14		—		14
Total current derivative assets	$	9	$	45	$	84	$	138	$	(54)	84		$	8	$	65	$	94	$	167	$	(66)	101
PPAs (b)											2												3
Current derivative instruments											$	86											$	104
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	12	$	54	$	51	$	117	$	(34)	$	83	$	14	$	51	$	45	$	110	$	(34)	$	76
Electric commodity	—		—		7		7		—		7		—		—		—		—		—		—
Total noncurrent derivative assets	$	12	$	54	$	58	$	124	$	(34)	$	90	$	14	$	51	$	45	$	110	$	(34)	$	76


	March 31, 2024												Dec. 31, 2023
	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	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	17	$	—	$	17	$	—	$	17
Other derivative instruments:
Commodity trading	$	7	$	79	$	5	$	91	$	(53)	$	38	$	6	$	86	$	5	$	97	$	(60)	$	37
Electric commodity	—		—		4		4		(4)		—		—		—		7		7		(7)		—
Natural gas commodity	—		—		—		—		—		—		—		12		—		12		—		12
Total current derivative liabilities	$	7	$	79	$	9	$	95	$	(57)	38		$	6	$	115	$	12	$	133	$	(67)	66
PPAs (b)											7												8
Current derivative instruments											$	45											$	74
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	14	$	52	$	42	$	108	$	(38)	$	70	$	16	$	50	$	37	$	103	$	(39)	$	64
Total noncurrent derivative liabilities	$	14	$	52	$	42	$	108	$	(38)	70		$	16	$	50	$	37	$	103	$	(39)	64
PPAs (b)											20												22
Noncurrent derivative instruments											$	90											$	86

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At March 31, 2024 and Dec. 31, 2023, derivative assets and liabilities include no obligations to return cash collateral. At March 31, 2024 and Dec. 31, 2023, derivative assets and liabilities include rights to reclaim cash collateral of $8 million and $7 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:












	Three Months Ended March 31
(Millions of Dollars)	2024		2023
Balance at Jan. 1	$	90	$	235
Purchases (a)	3		6
Settlements (a)	(51)		(29)
Net transactions recorded during the period:
Losses recognized in earnings (b)	—		(13)
Net gains (losses) recognized as regulatory assets and liabilities (a)	49		(121)
Balance at March 31	$	91	$	78

(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 March 31, 2024, other financial instruments for which the carrying amount did not equal fair value:


	March 31, 2024				Dec. 31, 2023
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	26,948	$	23,580	$	25,465	$	22,927

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of March 31, 2024 and Dec. 31, 2023, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.


9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended March 31
	2024		2023		2024		2023
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	19	$	18	$	—	$	—
Interest cost (a)	38		40		5		5
Expected return on plan assets (a)	(52)		(52)		(4)		(4)

Amortization of net loss (a)	7		5		1		1

Net periodic benefit cost	12		11		2		2
Effects of regulation	4		5		—		—
Net benefit cost recognized for financial reporting	$	16	$	16	$	2	$	2

(a)The components of net periodic cost other than the service cost component are included in the line item “Other income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.

In January 2024, contributions totaling $100 million were made across Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2024.


10. 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.

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 in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected imminently. Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial.

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 April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized $35 million of losses for the verdict in 2023, including estimated interest and other costs. In early 2024, PSCo and CORE each filed appeals of the trial court’s decision to the Colorado Court of Appeals.

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Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (the “Sheriff’s Report”). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.

PSCo is aware of 302 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.

In September 2023, the Boulder County District Court Judge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025. Discovery is now underway.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.

Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.

In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

2024 Smokehouse Creek Fire Complex — Beginning on February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which news reports indicate burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the “Smokehouse Creek Fire Complex”). The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed. SPS is continuing to conduct investigations into other potential ignitions associated with the Smokehouse Creek Fire Complex. According to the Texas A&M Forest Service’s Incident Viewer and news reports, as of March 19, 2024, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.

On March 12, 2024, the Speaker of the Texas House of Representatives created the Investigative Committee on the Panhandle Wildfires (the “Investigative Committee”). The Investigative Committee held public hearings in Pampa, Texas, between April 2 and April 4, 2024, and stated that it plans to issue a report by early May 2024.

SPS is aware of approximately 15 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex, including one putative class action on behalf of persons or entities who owned rangelands or pastures that were damaged by the fire. The complaints generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. SPS has also received approximately 46 claims for losses related to the Smokehouse Creek Fire Complex through its claims process.

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Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.

Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.

Based on the current state of the law and the facts and circumstances available to Xcel Energy as of the date of this filing, Xcel Energy believes it is probable that it will incur a loss in connection with the Smokehouse Creek Fire Complex and accordingly recorded a pre-tax charge in the amount of $215 million, presented in other current liabilities as of March 31, 2024 (before available insurance). The aggregate liability of $215 million for claims in connection with the Smokehouse Creek Fire Complex (before available insurance) corresponds to the lower end of the range of Xcel Energy’s reasonably estimable range of losses, and is subject to change based on additional information. This $215 million estimate does not include, among other things, amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) compensation claims for damage to trees, railroad lines, or oil and gas equipment, or (v) other amounts that are not reasonably estimable.

Xcel Energy is unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.

The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.

SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. As of March 31, 2024, SPS has recorded an insurance receivable for $215 million within prepayments and other current assets. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

Rate Matters and Other

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

Sherco —In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.

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

In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota responded that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.

In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota. In 2023, NSP-Minnesota and various parties filed recommendations, including the DOC which recommended a $56 million customer refund. The Xcel Large Industrial customer group recommended a refund of $72 million. A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote.

Environmental

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

Site Remediation

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

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

MGP, Landfill and Disposal Sites

Xcel Energy is investigating, remediating or performing post-closure actions at 12 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).

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Xcel Energy has recognized approximately $20 million of costs/liabilities from final resolution of these issues; however, the outcome and timing are unknown. In addition, there may be regulatory recovery, 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, including the CCR Rule. As a specific requirement of the CCR Rule, utilities must complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.

If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures.

Investigation and/or corrective action related to groundwater impacts are currently underway at four Xcel Energy sites under the federal CCR program at a current estimated cost of at least $40 million. A liability has been recorded, deferred accounting related to these costs has been approved by the CPUC and amounts are expected to be fully recoverable through regulatory mechanisms.

For required coal ash disposal, PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $45 million. An estimated liability has been recorded, deferred accounting related to these costs has been approved by the CPUC and amounts 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 $50 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.

Environmental Requirements — Air

Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations for ozone under the “Good Neighbor” provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. The rule establishes an allowance trading program for NOx that will impact Xcel Energy fossil fuel-fired electric generating facilities. Subject facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. Guidelines are also established for allowance banking and emission limit backstops.

While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms.

SPS and NSP-Minnesota have joined other companies in litigation challenging the EPA’s disapproval of Texas and Minnesota state implementation plans. Currently, the regulation is under a judicial stay for both Texas and Minnesota. The regulation may become applicable in those states in the future, depending on the outcome of the litigation. The rule is in effect in NSP-Wisconsin but has been managed without the additional need for allowances.

In February 2024, the EPA proposed to partially disapprove New Mexico’s state implementation plan and bring New Mexico into the federal Good Neighbor Plan. Xcel Energy continues to evaluate impacts to generation units at SPS.

Leases

Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.

Components of lease expense:


	Three Months Ended March 31
(Millions of Dollars)	2024		2023
Operating leases
PPA capacity payments	$	58	$	60
Other operating leases (a)	11		12
Total operating lease expense (b)	$	69	$	72
Finance leases
Amortization of ROU assets	$	1	$	1
Interest expense on lease liability	4		4
Total finance lease expense	$	5	$	5

(a)Includes short-term lease expense of $1 million and $2 million for 2024 and 2023, respectively.

(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

Commitments under operating and finance leases as of March 31, 2024:


(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)
Total minimum obligation	$	1,173	$	277	$	1,450	$	215
Interest component of obligation	(146)		(96)		(242)		(152)
Present value of minimum obligation	$	1,027	181		1,208		63
Less current portion					(228)		(2)
Noncurrent operating and finance lease liabilities					$	980	$	61

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

Variable Interest Entities

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

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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 Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had approximately 3,751 MW of capacity under long-term PPAs as of both March 31, 2024 and Dec. 31, 2023, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2041.

Other

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.

As of March 31, 2024 and Dec. 31, 2023, Xcel Energy had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were approximately $75 million at both March 31, 2024 and Dec. 31, 2023, 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.


11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of tax:


	Three Months Ended March 31, 2024						Three Months Ended March 31, 2023
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	$	(53)	$	(41)	$	(94)	$	(54)	$	(39)	$	(93)
Other comprehensive gain (loss) before reclassifications	22		—		22		(5)		—		(5)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)	1		—		1		1		—		1

Net current period other comprehensive income (loss)	23		—		23		(4)		—		(4)
Accumulated other comprehensive loss at March 31	$	(30)	$	(41)	$	(71)	$	(58)	$	(39)	$	(97)

(a)Included in interest charges.

12. 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, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

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Xcel Energy had equity method investments of $247 million and $244 million as of March 31, 2024 and Dec. 31, 2023, respectively, included in the natural gas utility and all other segments.

Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

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

Xcel Energy’s segment information:


	Three Months Ended March 31
(Millions of Dollars)	2024		2023
Regulated Electric
Operating revenues	$	2,685	$	2,763
Intersegment revenue	1		—
Total revenues	$	2,686	$	2,763
Net income	358		296
Regulated Natural Gas
Operating revenues	$	941	$	1,288
Intersegment revenue	1		1
Total revenues	$	942	$	1,289
Net income	158		159
All Other
Total revenues	$	23	$	29
Net loss	(28)		(37)
Consolidated Total
Total revenues	$	3,651	$	4,081
Reconciling eliminations	(2)		(1)
Total operating revenues	$	3,649	$	4,080
Net income	488		418

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP.

Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)

GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. For the three months ended March 31, 2024 and 2023, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole.

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Summarized diluted EPS for Xcel Energy:


	Three Months Ended March 31
Diluted Earnings (Loss) Per Share	2024		2023
PSCo	$	0.39	$	0.39
NSP-Minnesota	0.38		0.25
SPS	0.10		0.10
NSP-Wisconsin	0.08		0.08
Earnings from equity method investments — WYCO	0.01		0.01
Regulated utility	0.96		0.83
Xcel Energy Inc. and Other	(0.08)		(0.07)
GAAP diluted EPS	0.88		0.76

Summary of Earnings

Xcel Energy — Xcel Energy’s first quarter GAAP and ongoing diluted earnings were $0.88 per share, compared with $0.76 per share in the same period in 2023. The increase in earnings per share was primarily driven by increased recovery of infrastructure investments, higher AFUDC and lower O&M expenses, partially offset by increased interest charges and depreciation. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

PSCo — GAAP and ongoing earnings were flat for the first quarter primarily reflecting increased recovery of electric infrastructure investments, which was offset by unfavorable weather and increased depreciation and interest charges.

NSP-Minnesota — GAAP and ongoing earnings increased $0.13 per share for the first quarter of 2024. The change was driven by increased recovery of electric and natural gas infrastructure investments and lower O&M expenses, partially offset by higher interest expenses and depreciation.

SPS — GAAP and ongoing earnings were flat for the first quarter of 2024 primarily due to regulatory rate outcomes and lower O&M expenses, offset by increased depreciation and amortization expenses.

NSP-Wisconsin — GAAP and ongoing earnings were flat for the first quarter of 2024 as lower O&M expenses were offset by increased depreciation.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments. The decline in earnings is largely due to increased interest rates.

Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in 2024 EPS compared to 2023:


Diluted Earnings (Loss) Per Share	Three Months Ended March 31
GAAP and ongoing diluted EPS — 2023	$	0.76

Components of change - 2024 vs. 2023
Lower cost of natural gas sold and transported (a)	0.49
Lower electric fuel and purchased power (a)	0.23
Lower O&M expenses	0.06
Higher AFUDC	0.04

Lower natural gas revenues	(0.47)
Lower electric revenues	(0.11)
Higher depreciation and amortization	(0.05)
Higher interest charges	(0.05)
Other, net	(0.02)
GAAP and ongoing diluted EPS — 2024	0.88

(a)Cost of natural gas sold and transported and electric fuel and purchased power are generally recovered through regulatory recovery mechanisms and offset in revenue.

Statement of Income Analysis

The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

Estimated Impact of Temperature Changes on Regulated Earnings —Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.

As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.

Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.

Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.

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Normal weather conditions are defined as either the 10, 20 or 30 year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.

Percentage increase (decrease) in normal and actual HDD:


	Three Months Ended March 31
	2024 vs. Normal		2023 vs. Normal		2024 vs. 2023
HDD	(11.4)	%	1.4	%	(12.6)	%

Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:


	Three Months Ended March 31
	2024 vs. Normal		2023 vs. Normal		2024 vs. 2023
Retail electric	$	(0.029)	$	0.002	$	(0.031)
Decoupling and sales true-up	0.016		(0.006)		0.022
Electric total	$	(0.013)	$	(0.004)	$	(0.009)
Firm natural gas	(0.027)		0.029		(0.056)
Decoupling	$	0.017	$	—	$	0.017
Gas total	$	(0.010)	$	0.029	$	(0.039)
Total	$	(0.023)	$	0.025	$	(0.048)

Sales — Sales growth (decline) for actual and weather-normalized sales in 2024 compared to 2023:


	Three Months Ended March 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(2.2)	%	(5.7)	%	(1.7)	%	(7.3)	%	(4.0)	%
Electric C&I	0.4		(3.1)		7.4		(1.8)		1.0
Total retail electric sales	(0.5)		(4.0)		5.7		(3.5)		(0.5)
Firm natural gas sales	(9.1)		(14.4)		N/A		(14.6)		(11.1)



	Three Months Ended March 31
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	0.8	%	(1.0)	%	(2.9)	%	(3.0)	%	(0.8)	%
Electric C&I	1.0		(2.2)		7.5		(1.5)		1.6
Total retail electric sales	0.9		(1.8)		5.5		(2.0)		0.9
Firm natural gas sales	4.7		1.2		N/A		(3.1)		3.0


	Three Months Ended March 31 (Leap Year Adjusted)
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(0.3)	%	(2.1)	%	(4.1)	%	(4.1)	%	(1.9)	%
Electric C&I	(0.1)		(3.3)		6.3		(2.5)		0.5
Total retail electric sales	(0.2)		(2.9)		4.3		(3.0)		(0.3)
Firm natural gas sales	3.4		(0.1)		N/A		(4.3)		1.7

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date

•PSCo — Residential sales decreased due to a 1.5% decrease in use per customer, partially offset by customer growth of 1.3%. The C&I sales decline was related to decreased use per customer, primarily in the information and professional services sectors partially offset by increases in the manufacturing and health care sectors.

•NSP-Minnesota — Residential sales decreased due to a 3.5% decrease in use per customer, partially offset by a 1.5% increase in customers. C&I sales declined due to decreased use per customer, largely in the manufacturing sector.

•SPS — Residential sales declined as a result of a 4.6% decrease in use per customer, partially offset by 0.5% customer growth. C&I sales increased due to higher use per customer, primarily driven by the energy sector.

•NSP-Wisconsin — Residential sales declined due to a 4.9% decrease in use per customer, partially offset by 0.8% increase in customers. C&I sales decline was associated with decreased use per customer, experienced largely in the professional services and manufacturing sectors.

Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date

•Increase in natural gas sales was driven by continued strength in PSCo residential and C&I use per customer. Additionally, overall residential and C&I customer growth was 1.1% and 0.6%, respectively.

Electric Revenues

Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes. In the first quarter, electric revenues decreased $78 million.


(Millions of Dollars)	Three Months Ended March 31, 2024 vs. 2023
Recovery of lower cost of electric fuel and purchased power	$	(178)
Wholesale generation revenues	(11)
Estimated impact of weather (net of sales true-up)	(8)
PTCs flowed back to customers (offset by lower ETR)	(8)

Regulatory rate outcomes (MN, CO, TX, NM, WI and ND)	66
Non-fuel riders	34
Conservation and demand side management (offset in expense)	20
Sales and demand (a)	15


Other (net)	(8)

Total decrease	$	(78)

(a)Sales excludes weather impact, net of sales true-up mechanism in Minnesota.

Natural Gas Revenues

Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. In the first quarter, natural gas revenues decreased $347 million.

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(Millions of Dollars)	Three Months Ended March 31, 2024 vs. 2023
Recovery of lower cost of natural gas	$	(359)
Estimated impact of weather (net of decoupling)	(29)
Regulatory rate outcomes (MN, WI, ND and MI)	22
Retail sales growth (net of decoupling in Minnesota)	10
Infrastructure and integrity riders	3


Other (net)	6
Total decrease	$	(347)

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. However, these incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues and have minimal earnings impact.

Electric fuel and purchased power expenses decreased $169 million for the first quarter of 2024. The decrease is primarily due to lower commodity prices and timing of fuel recovery.

Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $361 million for the first quarter of 2024. The decrease is primarily due to l lower commodity prices, timing of fuel recovery and decreased volumes.

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $45 million for the first quarter. The decrease was primarily due to decreased labor and benefit costs, gain on land sale, and lower bad debt expenses.

Depreciation and Amortization — Depreciation and amortization increased $34 million for the first quarter as a result of system expansion, offset by depreciation life extensions implemented in the Minnesota Electric Rate Case.

Interest Charges — Interest charges increased $38 million for the first quarter, largely due to increased long-term debt levels and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $22 million for the first quarter driven by increased investment in renewable projects in 2024.


Public Utility Regulation and Other

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts, and the cost of capital.

In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings

2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In December 2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).

On April 19, 2024, four parties filed direct testimony. The DOC, OAG, and CUB were the only parties to quantify recommended financial adjustments. The OAG and CUB provided limited comments, recommending a reduction of approximately $1 million of O&M expenses each. The CUB additionally recommended a reduction to ROE.

Proposed DOC modifications to NSP-Minnesota’s request were as follows:


(Millions of Dollars)
NSP-Minnesota’s filed base revenue request	$	59
Recommended adjustments:
Rate of return	(7)
Operating & maintenance expenses	(4)
Plant investments	(3)
Other, net	(2)
Total adjustments	$	(16)
Total proposed revenue change	$	43

Positions on NSP-Minnesota’s filed rate request were as follows:


Recommended Position	DOC		CUB
ROE	9.40	%	9.00-9.40%
Equity ratio	52.50	%	N/A

Procedural schedule:

•Mediation: May 17, 2024 (day subject to availability)

•Rebuttal testimony: May 24, 2024

•Evidentiary hearings: July 10-12, 2024

•ALJ report: October 28, 2024

•MPUC Order Due: March 14, 2025

2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), a 2024 test year, ROE of 10.20%, an equity ratio of 52.5% and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.

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Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota submitted an annual fuel clause adjustment true-up petition to the MPUC, with a requested refund of $126 million for fuel over-recoveries in 2023. In April 2024, the DOC recommended the MPUC approve the non-nuclear aspects of the petition. The DOC stated it intends to submit supplemental comments in the second quarter of 2024 with recommendations related to costs associated with operation of NSP-Minnesota’s nuclear units, which includes costs associated with an outage at the Prairie Island generating station.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023, appropriately represent, in all material respects, the current status of nuclear power operations.

NSP System

2022 Upper Midwest IRP Resource Acquisition — Following the MPUC’s approval of NSP-Minnesota and NSP-Wisconsin’s latest IRP in April 2022, NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the IRP.

•In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of 800 MW of firm dispatchable resources. In January 2024, NSP-Minnesota and other companies submitted proposed resources and filed for project approval with the MPUC. NSP-Minnesota expects a decision by the second quarter of 2025.

•In July 2023, NSP-Wisconsin issued an RFP seeking approximately 650 MW of solar and/or solar plus storage development assets that will be developed in the 2027-2029 timeframe to replace the capacity from the retiring King Generating Station. The RFP closed in September 2023 and bids are being evaluated.

•In October 2023, NSP-Minnesota issued an RFP seeking approximately 1,200 MW of wind development assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023 and NSP-Minnesota expects to file for approval of recommended projects by mid-2024.

2024 Upper Midwest Resource Plan — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC which included the following key items:

•Reduced carbon emissions by more than 80%, potentially up to 88%, by 2030.

•Extends the operation of Prairie Island and Monticello through the early 2050s.

•Adds 3,600 MWs of new wind and solar resources by 2030.

•Adds 600 MWs of battery energy storage by 2030.

•Adds more than 2,200 MWs of dispatchable resources by 2030.

These proposed resources are in addition to projects already approved by the MPUC. NSP-Minnesota anticipates a MPUC decision in 2025.

PSCo

Pending and Recently Concluded Regulatory Proceedings

Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023. PSCo has requested a proposed effective date of Nov. 1, 2024.

PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.

Procedural schedule:

•Intervenor testimony: July 11, 2024

•Rebuttal testimony: Aug. 15, 2024

•Settlement deadline: Aug. 27, 2024

•Evidentiary hearing: Sept. 4-12, 2024

•Statement of position: Sept. 26, 2024

Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs. PSCo expects to invest approximately $4.8 billion in generation resources under the portfolio for the benefit of its customers and achieving the state’s clean energy goals.

In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in related proceedings throughout 2024.

In March 2024, PSCo filed its first CPCN for the Rocky Mountain and Arroyo 2 solar projects on an expedited basis in order to begin construction in time for planned in-service dates in 2025 and 2026. PSCo expects to file additional generation and transmission CPCNs throughout the remainder of 2024.

Transportation Electrification Plan — In April 2024, the CPUC approved PSCo’s TEP with modification, including a three-year budget of $264 million and continued cost recovery through the TEP rider. The CPUC approved PSCo’s proposal to offer rebates for residential chargers and wiring to be paired with residential managed charging programs and vehicle rebates for Income-Qualified customers, as well as its proposal to offer rebates for commercial public chargers and electric vehicle supply infrastructure. Additionally, the CPUC approved PSCo’s proposed budget to support innovation projects including electric school buses, Vehicle-to-Everything demonstrations, and stakeholder-driven projects with a focus on disproportionately impacted communities. The Commission also approved a WACC return on rebates with a 3-year amortization.

Wildfire Mitigation Plan — PSCo will file a Wildfire Mitigation Plan and request for recovery of costs to execute the plan in the second quarter of 2024. The plan will include a number of new and expanded programs from the currently approved Wildfire Mitigation Plan including distribution undergrounding, distribution covered conductor, enhanced wildfire safety settings, increased scope and scale for vegetation management, updated frequency of inspections of poles and other equipment in wildfire risk zones, transmission line rebuilds, proactive line de-energization and situational awareness programs including weather stations, cameras, and other monitoring software.

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CPUC Proactive Line De-Energization Investigation — In early April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 MPH to reduce potential wildfire risk. Later in April, the CPUC opened a Miscellaneous Proceeding to seek information on:

•Utility operations during, after, and leading up to the wind event to identify risks, de-energize lines and re-energize lines.

•Customer communications (including what was communicated to whom and when).

•Community engagement to assess the coordination with neighboring electric providers, telecom companies, 911, medical providers, and other first responders and community leaders.

The CPUC held sessions to hear public comments and will hold Commissioner Information Meetings in May 2024 to hear directly from PSCo, impacted customers, and other first responders and community leaders on power shutoffs. A potential order, rules, procedures or report is expected later this year.

Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).

In November 2023, the CPUC approved PSCo’s natural gas price risk management plan, establishing upper and lower limits for changes in the GCA rate. As a result costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit are deferred as a reserve against future cost increases.

The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. In the first quarter of 2024, the CPUC discussed proposed rules for the gas utility. The written notice of the proposed rule is expected in the second quarter of 2024, which will be followed by a comment period. The Commission's proposed rules for electric utilities are expected later in 2024.

SPS

Pending and Recently Concluded Regulatory Proceedings

2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%). The request was based on a ROE of 10.65%, an equity ratio of 54.6%, a retail rate base of $3.6 billion and a change in the Tolk coal plant depreciation life from 2034 to 2028.

In December 2023, SPS, PUCT Staff and intervenors filed a black box settlement. Key terms include:

•A base rate increase of $65 million effective back to July 13, 2023.

•A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.

•The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.

•Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses.

Interim rates based on the settlement went into effect on Feb. 1, 2024. On April 11, 2024, the PUCT unanimously approved the settlement without modification.

2022 All-Source RFP — In July 2023, SPS filed for approval of a Certificate of Convenience and Necessity for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. A decision from PUCT and NMPRC is expected in mid-2024.

The second portion of the portfolio includes a November 2023 filing for the approval of PPAs including 48 MW of battery energy storage and 230 MW of existing gas generation. Regulatory decisions on these PPA agreements are expected in the third quarter of 2024.

New Mexico Resource Plan — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. Based on load forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP. SPS expects to issue an RFP for new generation in July 2024. The RFP will be evaluated in the latter half of 2024 with portfolio selection expected in early 2025.

Other

Supply Chain

Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.

Solar Resources

In August 2023, the U.S. Department of Commerce completed its anti-circumvention investigation and concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.

An interim stay on tariffs remains in effect until June 2024 and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports (e.g., as a result of implementation of the Uyghur Forced Labor Protection Act), disruptions in solar imports from key suppliers or any new trade complaint could impact project timelines and costs.

On April 24, 2024, the American Alliance for Solar Manufacturing Trade Committee filed a petition related to new anti-dumping and countervailing duty cases targeting solar products from Cambodia, Malaysia, Thailand and Vietnam with the United States Department of Commerce and the United States International Trade Commission. Xcel Energy continues to assess the impacts (if any) of this trade complaint on its business.

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Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. The financial and operating environment also may have a significant effect on the operation of the business and results reported. Items considered critical, in addition to the matter noted below, are included within the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023.

Loss Contingencies – Wildfires

The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 10 accompanying the consolidated financial statements for additional information.

Environmental Regulation

Clean Air Act

Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Xcel Energy continues to evaluate the impact of these rules and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

Waste-to-Energy Air Regulations — In January 2024, the EPA proposed air regulations addressing new and existing large municipal waste combustors. The proposed rules lower current emission standards for certain pollutants and would require installation of new pollution controls and/or more intense use of existing pollution controls at French Island Generating Station. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

Coal Ash Regulation

In April 2024, the EPA published final rules to regulate additional areas under the CCR Rule for the first time, including legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities. The rule subjects these areas to groundwater monitoring, corrective action and closure and post-closure care requirements, among other requirements, with several of the deadlines accelerated. Xcel Energy believes that the cost of these requirements would be recoverable through rates based on prior state commission practices. In January 2024, PSCo received approval from the CPUC for deferred accounting for costs associated with compliance with the legacy CCR rule.

Emerging Contaminants of Concern

PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS but because PFAS are so ubiquitous in products and the environment, it may impact our operations.

In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA.

In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.

In February 2024, the EPA proposed to change the Resource Conservation and Recovery Act by adding nine PFAS to its list of hazardous constituents.

Final rules for all three proposals are expected in 2024 which could result in new obligations. Potential costs are uncertain until final rules are published and/or agency action is taken.

Effluent Limitation Guidelines

In April 2024, the EPA published final rules under the Clean Water Act, setting forth Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Xcel Energy continues to evaluate the impact of these rules and believes that any costs associated with these requirements would be recoverable through rates based on prior state commission practices.


Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.

Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.

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Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.

Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.

Fair value of net commodity trading contracts as of March 31, 2024:


	Futures / Forwards Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	$	2	$	(3)	$	(2)	$	—	$	(3)
NSP- Minnesota (b)	(4)		(7)		(9)		—		(20)
PSCo (a)	—		2		2		—		4
PSCo (b)	(5)		4		1		—		—
	$	(7)	$	(4)	$	(8)	$	—	$	(19)


	Options Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	$	—	$	—	$	13	$	7	$	20
PSCo (b)	1		—		—		—		1
	$	1	$	—	$	13	$	7	$	21

(a)Prices actively quoted or based on actively quoted prices.

(b)Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the three months ended March 31:


(Millions of Dollars)	2024		2023
Fair value of commodity trading net contracts outstanding at Jan. 1	$	1	$	(33)
Contracts realized or settled during the period	(1)		3
Commodity trading contract additions and changes during the period	2		28
Fair value of commodity trading net contracts outstanding at March 31	$	2	$	(2)

A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $4 million at March 31, 2024 and March 31, 2023.

The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:


(Millions of Dollars)	Three Months Ended March 31		Average		High		Low
2024	$	1	$	—	$	1	$	—
2023	1		1		1		—

Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 29% of its average enriched nuclear material requirements from Russia through 2030. Given the evolving situation in Ukraine and its global impacts, we have entered into additional contracts that cover potential supply interruptions of nuclear material from Russia. With these contracts, NSP-Minnesota has secured its enriched nuclear material requirements through 2028 with non-Russian material, which are in various stages of processing in Canada, Europe and the United States.

Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.

A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $8 million and $11 million in March 31, 2024 and 2023, respectively.

NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.

Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.

The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.

Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At March 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $25 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At March 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $37 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $36 million.

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Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.

Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.


Fair Value Measurements

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Note 8 to the consolidated financial statements for further information.


Liquidity and Capital Resources

Cash Flows

Operating Cash Flows


(Millions of Dollars)	Three Months Ended March 31
Cash provided by operating activities — 2023	$	1,537

Components of change — 2024 vs. 2023
Higher net income	70

Changes in deferred income taxes	227
Changes in working capital	(438)
Changes in net regulatory and other assets and liabilities	(346)
Cash provided by operating activities — 2024	$	1,050

Net cash provided by operating activities decreased $487 million for the three months ended March 31, 2024 compared with the prior year. The decrease was largely due to interim rate refunds in Minnesota, as well as the impact of decreased natural gas prices on accounts payable and receivables, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers.

Investing Cash Flows


(Millions of Dollars)	Three Months Ended March 31
Cash used in investing activities — 2023	$	(1,284)

Components of change — 2024 vs. 2023
Increased capital expenditures	(272)

Cash used in investing activities — 2024	$	(1,556)

Net cash used in investing activities increased $272 million for the three months ended March 31, 2024 compared with the prior year. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable projects.

Financing Cash Flows


(Millions of Dollars)	Three Months Ended March 31
Cash used in financing activities — 2023	$	(250)

Components of change — 2024 vs. 2023
Higher net short-term debt proceeds	(588)
Higher long-term debt issuances, net of repayments	1,728


Other financing activities	(12)
Cash provided by financing activities — 2024	$	878

Net cash provided by financing activities increased $1,128 million for the three months ended March 31, 2024 compared with the prior year. The increase was largely related to the amount/timing of debt issuances and repayments.

Capital Requirements

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.

Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.

•In January 2024, contributions of $100 million were made across four of Xcel Energy’s pension plans.

•In 2023, contributions of $50 million were made across four of Xcel Energy’s pension plans.

•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.

Capital Sources

Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.

Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of their revolving credit facility termination date for two additional one-year periods beyond the September 2027 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

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As of April 22, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,500	$	—	$	1,500	$	11	$	1,511
PSCo	700		30		670		656		1,326
NSP-Minnesota	700		15		685		411		1,096
SPS	500		101		399		29		428
NSP-Wisconsin	150		—		150		6		156
Total	$	3,550	$	146	$	3,404	$	1,113	$	4,517

(a)Credit facilities expire in September 2027.

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

Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of March 31, 2024, the authorized levels for these commercial paper programs are:

•$1.5 billion for Xcel Energy Inc.

•$700 million for PSCo.

•$700 million for NSP-Minnesota.

•$500 million for SPS.

•$150 million for NSP-Wisconsin.

Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.

Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.

2024 Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect the following:

Issuer

Security

Amount

Status

Tenor

Coupon

Xcel Energy Inc.

Senior Unsecured Notes

800

million

Completed

10 Year

5.50

NSP-Minnesota

First Mortgage Bonds

700

million

Completed

30 Year

5.40

PSCo

First Mortgage Bonds

1,200

million

Completed (a)

10 Year & 30 Year

5.35 % & 5.75 %

SPS

First Mortgage Bonds

600

million

Second Quarter

30 Year

N/A

NSP-Wisconsin

First Mortgage Bonds

400

million

Second Quarter

30 Year

N/A

(a)Bond was issued on April 4, 2024.

Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its at-the-market program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.

See Note 4 to the consolidated financial statements for further information.

Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a)

Key assumptions as compared with 2023 actual levels unless noted:

•Constructive outcomes in all pending rate case and regulatory proceedings.

•Normal weather patterns for the remainder of the year.

•Weather-normalized retail electric sales are projected to increase 1% to 2%.

•Weather-normalized retail firm natural gas sales are projected to be flat.

•Capital rider revenue is projected to increase $60 million to $70 million (net of PTCs).

•O&M expenses are projected to increase 1% to 2%.

•Depreciation expense is projected to increase approximately $290 million to $300 million. The change largely reflects changes in depreciation rates approved in the Texas rate case, which are largely offset in revenue and earnings neutral.

•Property taxes are projected to increase $20 million to $30 million.

•Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income.

•AFUDC - equity is projected to increase $65 million to $75 million.

•ETR is projected to be ~(4%) to (6%). The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral. The projected ETR does not reflect the potential impact of nuclear PTCs, which are also expected to flow back to customers.

(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.

Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:

• Deliver long-term annual EPS growth of 5% to 7% based off of a 2023 actual ongoing earnings base of $3.35 per share.

• Deliver annual dividend increases of 5% to 7%.

• Target a dividend payout ratio of 50% to 60%.

• Maintain senior secured debt credit ratings in the A range.

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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2023 under “Derivatives, Risk Management and Market Risk.”


ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.

As of March 31, 2024, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.

PART II — OTHER INFORMATION


ITEM 1 — LEGAL PROCEEDINGS

Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.

See Note 10 to the consolidated financial statements and Part I Item 2 for further information.


ITEM 1A — RISK FACTORS

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2023, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.


ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:

The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended March 31, 2024:


	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2024 - Jan. 31, 2024	—	$	—	—	—
Feb. 1, 2024 - Feb. 29, 2024	—	—		—	—
March 1, 2024 - March 31, 2024 (a)	788	52.69		—	—
	788			—	—

(a)Xcel Energy Inc. or one of its agents periodically purchases common shares in open-market transactions in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.


ITEM 5 — OTHER INFORMATION

None of the Company’s directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended March 31, 2024.

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ITEM 6 — EXHIBITS


*			Indicates incorporation by reference


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012	Xcel Energy Inc. Form 8-K dated May 16, 2012	3.01
3.02*	Bylaws of Xcel Energy Inc., as Amended and Restated on August 23, 2023	Xcel Energy Inc Form 8-K dated August 23, 2023	3.02
4.01*	Supplemental Indenture No. 18, dated as of February 29, 2024 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $800,000,000 aggregate principal amount of 5.50% Senior Notes, Series due March 15, 2034.	Xcel Energy Inc Form 8-K dated February 29, 2024	4.01
4.0 2*	Supplemental Trust Indenture dated as of February 1, 2024 between Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700,000,000 aggregate principal amount of 5.40% First Mortgage Bonds, Series due March 15, 2054.	NSP-Minnesota Form 8-K dated February 29, 2024	4.01
4.03*	Supplemental Indenture dated as of April 1, 2024, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating $450 million principal amount of 5.35% First Mortgage Bonds, Series No. 41 due 2034 and $750 million principal amount of 5.75% First Mortgage Bonds, Series No. 42 due 2054.	PSCo Form 8-K dated April 4, 2024	4.01
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.01	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		XCEL ENERGY INC.

4/25/2024	By:	/s/ MELISSA L. OSTROM
		Melissa L. Ostrom
		Vice President, Controller
		(Principal Accounting Officer)


	By:	/s/ BRIAN J. VAN ABEL
		Brian J. Van Abel
		Executive Vice President, Chief Financial Officer
		(Principal Financial Officer)