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 June 30, 2024

or

☐ 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 July 30, 2024
Common Stock, $2.50 par value	557,500,681 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	24
Item 3 —	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4 —	Controls and Procedures	35
PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	35
Item 1A —	Risk Factors	35
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 5 —	Other Information	36
Item 6 —	Exhibits	36
SIGNATURES		37

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.

2

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
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
DCRF	Distribution Cost Recovery Factor
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
IRA	Inflation Reduction Act
IRP	Integrated Resource Plan
LLC	Limited liability company
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
PFAS	Per- and Polyfluoroalkyl Substances
PIM	Performance incentive mechanism
PPA	Power purchase agreement
PSPS	Public safety power shutoff
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.
Staff	CPUC Staff
TEP	Transportation electrification plan
THI	Temperature-humidity index
UCA	Colorado Office of the Utility Consumer Advocate
VaR	Value at Risk
WACC	Weighted average cost of capital

Measurements
MW	Megawatts

3

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, expected pension contributions, and expected impact on our results of operations, financial condition and cash flows of interest rate changes, increased credit exposure, and legal proceeding outcomes, 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 Securities and Exchange Commission, 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.

4

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 June 30				Six Months Ended June 30
	2024		2023		2024		2023
Operating revenues
Electric	$	2,659	$	2,601	$	5,344	$	5,364
Natural gas	355		393		1,296		1,681
Other	14		28		37		57
Total operating revenues	3,028		3,022		6,677		7,102
Operating expenses
Electric fuel and purchased power	855		1,030		1,803		2,147
Cost of natural gas sold and transported	118		170		601		1,014
Cost of sales — other	1		11		9		23
Operating and maintenance expenses	662		628		1,267		1,278
Conservation and demand side management expenses	86		63		183		139
Depreciation and amortization	703		565		1,361		1,189
Taxes (other than income taxes)	154		137		325		321
Total operating expenses	2,579		2,604		5,549		6,111
Operating income	449		418		1,128		991
Other income, net	22		11		36		16
Earnings from equity method investments	8		9		16		20
Allowance for funds used during construction — equity	38		18		75		37
Interest charges and financing costs
Interest charges — includes other financing costs	319		268		610		521
Allowance for funds used during construction — debt	(16)		(12)		(30)		(22)
Total interest charges and financing costs	303		256		580		499
Income before income taxes	214		200		675		565
Income tax benefit	(88)		(88)		(115)		(141)
Net income	$	302	$	288	$	790	$	706
Weighted average common shares outstanding:
Basic	557		551		556		551
Diluted	557		552		556		551
Earnings per average common share:
Basic	$	0.54	$	0.52	$	1.42	$	1.28
Diluted	0.54		0.52		1.42		1.28
See Notes to Consolidated Financial Statements

5

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in millions)

	Three Months Ended June 30				Six Months Ended June 30
	2024		2023		2024		2023
Net income	$	302	$	288	$	790	$	706
Other comprehensive income
Pension and retiree medical benefits:
Reclassifications of losses to net income, net of tax	4		1		4		1
Derivative instruments:
Net fair value increase, net of tax	—		13		22		8
Reclassification of losses to net income, net of tax	—		1		1		2
Total other comprehensive income	4		15		27		11
Total comprehensive income	$	306	$	303	$	817	$	717
See Notes to Consolidated Financial Statements

6

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in millions)

	Six Months Ended June 30
	2024		2023
Operating activities
Net income	$	790	$	706
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,370		1,202
Nuclear fuel amortization	53		53
Deferred income taxes	285		(192)
Allowance for equity funds used during construction	(75)		(37)
Earnings from equity method investments	(16)		(20)
Dividends from equity method investments	18		18
Provision for bad debts	28		36
Share-based compensation expense	17		12
Changes in operating assets and liabilities:
Accounts receivable	148		225
Accrued unbilled revenues	6		364
Inventories	(2)		100
Other current assets	(53)		39
Accounts payable	4		(443)
Net regulatory assets and liabilities	150		569
Other current liabilities	(439)		(74)
Pension and other employee benefit obligations	(98)		(37)
Other, net	54		(66)
Net cash provided by operating activities	2,240		2,455
Investing activities
Capital/construction expenditures	(3,368)		(2,599)
Purchase of investment securities	(469)		(416)
Proceeds from the sale of investment securities	450		399
Other, net	(16)		(23)
Net cash used in investing activities	(3,403)		(2,639)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	17		(269)
Proceeds from issuances of long-term debt	3,644		1,741
Repayments of long-term debt	(550)		(650)
Proceeds from issuance of common stock	101		75
Dividends paid	(575)		(536)
Other, net	(5)		(13)
Net cash provided by financing activities	2,632		348
Net change in cash, cash equivalents and restricted cash	1,469		164
Cash, cash equivalents and restricted cash at beginning of period	129		111
Cash, cash equivalents and restricted cash at end of period	$	1,598	$	275
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(517)	$	(461)
Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers	351		(49)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	520	$	497
Inventory transfers to property, plant and equipment	164		78
Operating lease right-of-use assets	40		50
Allowance for equity funds used during construction	75		37
Issuance of common stock for reinvested dividends and/or equity awards	35		32
See Notes to Consolidated Financial Statements

7

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in millions, except share and per share data

	June 30, 2024		Dec. 31, 2023
Assets
Current assets
Cash and cash equivalents	$	1,598	$	129
Accounts receivable, net	1,138		1,315
Accrued unbilled revenues	847		853
Inventories	622		711
Regulatory assets	630		611
Derivative instruments	234		104
Prepaid taxes	89		52
Prepayments and other	541		294
Total current assets	5,699		4,069
Property, plant and equipment, net	53,890		51,642
Other assets
Nuclear decommissioning fund and other investments	3,791		3,599
Regulatory assets	2,751		2,798
Derivative instruments	84		76
Operating lease right-of-use assets	1,145		1,217
Other	567		678
Total other assets	8,338		8,368
Total assets	$	67,927	$	64,079
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	854	$	552
Short-term debt	802		785
Accounts payable	1,546		1,668
Regulatory liabilities	781		528
Taxes accrued	360		557
Accrued interest	299		251
Dividends payable	305		289
Derivative instruments	44		74
Operating lease liabilities	226		226
Other	683		722
Total current liabilities	5,900		5,652
Deferred credits and other liabilities
Deferred income taxes	5,280		4,885
Deferred investment tax credits	56		60
Regulatory liabilities	5,959		5,827
Asset retirement obligations	3,390		3,218
Derivative instruments	91		86
Customer advances	154		167
Pension and employee benefit obligations	371		469
Operating lease liabilities	961		1,038
Other	95		148
Total deferred credits and other liabilities	16,357		15,898
Commitments and contingencies
Capitalization
Long-term debt	27,716		24,913
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 557,337,051 and 554,941,703 shares outstanding at June 30, 2024 and December 31, 2023, respectively	1,393		1,387
Additional paid in capital	8,589		8,465
Retained earnings	8,039		7,858
Accumulated other comprehensive loss	(67)		(94)
Total common stockholders’ equity	17,954		17,616
Total liabilities and equity	$	67,927	$	64,079
See Notes to Consolidated Financial Statements

8

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 June 30, 2024 and 2023
Balance at March 31, 2023	550,222,192	$	1,376	$	8,169	$	7,370	$	(97)	$	16,818
Net income						288				288
Other comprehensive loss								15		15
Dividends declared on common stock ($0.52 per share)						(286)				(286)
Issuances of common stock	1,153,063	2		75						77
Share-based compensation				3		(1)				2
Balance at June 30, 2023	551,375,255	$	1,378	$	8,247	$	7,371	$	(82)	$	16,914
Balance at March 31, 2024	555,470,302	$	1,389	$	8,481	$	8,042	$	(71)	$	17,841
Net income						302				302
Other comprehensive income								4		4
Dividends declared on common stock ($0.5475 per share)						(305)				(305)
Issuances of common stock	1,866,749	4		97						101
Share-based compensation				11						11
Balance at June 30, 2024	557,337,051	$	1,393	$	8,589	$	8,039	$	(67)	$	17,954
	Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
	Shares	Par Value		Additional Paid In Capital
Six Months Ended June 30, 2024 and 2023
Balance at Dec. 31, 2022	549,578,018	$	1,374	$	8,155	$	7,239	$	(93)	$	16,675
Net income						706				706
Other comprehensive income								11		11
Dividends declared on common stock ($1.04 per share)						(572)				(572)
Issuances of common stock	1,797,237	4		91						95
Share-based compensation				1		(2)				(1)
Balance at June 30, 2023	551,375,255	$	1,378	$	8,247	$	7,371	$	(82)	$	16,914
Balance at Dec. 31, 2023	554,941,703	$	1,387	$	8,465	$	7,858	$	(94)	$	17,616
Net income						790				790
Other comprehensive income								27		27
Dividends declared on common stock ($1.095 per share)						(609)				(609)
Issuances of common stock	2,395,348	6		107						113
Share-based compensation				17						17
Balance at June 30, 2024	557,337,051	$	1,393	$	8,589	$	8,039	$	(67)	$	17,954
See Notes to Consolidated Financial Statements

9

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 June 30, 2024 and Dec. 31, 2023; the results of Xcel Energy’s operations, including the components of net income, comprehensive income and changes in stockholders’ equity for the three and six months ended June 30, 2024 and 2023; and Xcel Energy’s cash flows for the six months ended June 30, 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 June 30, 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)	June 30, 2024		Dec. 31, 2023
Accounts receivable, net
Accounts receivable	$	1,244	$	1,443
Less allowance for bad debts	(106)		(128)
Accounts receivable, net	$	1,138	$	1,315

(Millions of Dollars)	June 30, 2024		Dec. 31, 2023
Inventories
Materials and supplies	$	394	$	377
Fuel	181		211
Natural gas	47		123
Total inventories	$	622	$	711

(Millions of Dollars)	June 30, 2024		Dec. 31, 2023
Property, plant and equipment, net
Electric plant	$	53,883	$	52,494
Natural gas plant	9,363		9,080
Common and other property	3,296		3,190
Plant to be retired (a)	1,890		2,055
Construction work in progress	4,355		2,873
Total property, plant and equipment	72,787		69,692
Less accumulated depreciation	(19,300)		(18,399)
Nuclear fuel	3,444		3,337
Less accumulated amortization	(3,041)		(2,988)
Property, plant and equipment, net	$	53,890	$	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.

10

4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Commercial paper and term loan borrowings outstanding for Xcel Energy:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2024			Year Ended Dec. 31, 2023
Borrowing limit	$	3,550		$	3,550
Amount outstanding at period end	802			785
Average amount outstanding	449			491
Maximum amount outstanding	802			1,241
Weighted average interest rate, computed on a daily basis	5.54		%	5.12		%
Weighted average interest rate at period end	5.54			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 $43 million and $44 million of letters of credit outstanding under the credit facilities at June 30, 2024 and Dec. 31, 2023, respectively. Amounts approximate their fair value and are subject to fees.

Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities 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 June 30, 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	$	802	$	698
PSCo	700		31		669
NSP-Minnesota	700		12		688
SPS	500		—		500
NSP-Wisconsin	150		—		150
Total	$	3,550	$	845	$	2,705

(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 June 30, 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 June 30, 2024, NSP-Minnesota had $70 million of outstanding letters of credit under the $75 million bilateral credit agreement.

Long-Term Borrowings and Other Financing Instruments

During the six months ended June 30, 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.

•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.

•NSP-Wisconsin issued $400 million of 5.65% First Mortgage Bonds due June 15, 2054.

•SPS issued $600 million of 6.00% First Mortgage Bonds due June 1, 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 six months ended June 30, 2024, 1.68 million shares ($93 million in net proceeds and $1 million in transaction fees paid) were issued under the ATM program. As of June 30, 2024, approximately $2.2 billion remained available for sale under the ATM program.

Equity through DRIP and Benefits Program — Xcel Energy issued $40 million and $61 million of equity through the DRIP and benefits programs during the six months ended June 30, 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 June 30, 2024
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	801	$	191	$	—	$	992
C&I	1,335		97		6		1,438
Other	36		—		3		39
Total retail	2,172		288		9		2,469
Wholesale	137		—		—		137
Transmission	148		—		—		148
Other	17		42		—		59
Total revenue from contracts with customers	2,474		330		9		2,813
Alternative revenue and other	185		25		5		215
Total revenues	$	2,659	$	355	$	14	$	3,028

11

	Three Months Ended June 30, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	748	$	216	$	15	$	979
C&I	1,337		124		8		1,469
Other	37		—		1		38
Total retail	2,122		340		24		2,486
Wholesale	174		—		—		174
Transmission	157		—		—		157
Other	4		32		—		36
Total revenue from contracts with customers	2,457		372		24		2,853
Alternative revenue and other	144		21		4		169
Total revenues	$	2,601	$	393	$	28	$	3,022

	Six Months Ended June 30, 2024
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,660	$	759	$	10	$	2,429
C&I	2,611		371		15		2,997
Other	70		—		5		75
Total retail	4,341		1,130		30		5,501
Wholesale	310		—		—		310
Transmission	306		—		—		306
Other	36		101		—		137
Total revenue from contracts with customers	4,993		1,231		30		6,254
Alternative revenue and other	351		65		7		423
Total revenues	$	5,344	$	1,296	$	37	$	6,677

	Six Months Ended June 30, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,622	$	1,005	$	28	$	2,655
C&I	2,690		547		20		3,257
Other	73		—		2		75
Total retail	4,385		1,552		50		5,987
Wholesale	398		—		—		398
Transmission	320		—		—		320
Other	13		80		—		93
Total revenue from contracts with customers	5,116		1,632		50		6,798
Alternative revenue and other	248		49		7		304
Total revenues	$	5,364	$	1,681	$	57	$	7,102

6. Income Taxes

Reconciliation between the statutory rate and ETR:

	Three Months Ended June 30				Six Months Ended June 30
	2024		2023		2024		2023
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	5.1		5.1		4.9		4.9
(Decreases) increases:
Wind PTCs (a)	(60.3)		(64.0)		(36.8)		(44.1)
Plant regulatory differences (b)	(7.0)		(6.3)		(6.0)		(5.8)
Other tax credits, net operating loss & tax credit allowances	(1.3)		(1.4)		(0.8)		(1.5)
Other, net	1.4		1.6		0.7		0.5
Effective income tax rate	(41.1)	%	(44.0)	%	(17.0)	%	(25.0)	%

(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. 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.

12

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

	Three Months Ended June 30		Six Months Ended June 30
(Shares in Millions)	2024	2023	2024	2023
Basic	557	551	556	551
Diluted (a)	557	552	556	551

(a)Diluted common shares outstanding included common stock equivalents of 0.2 million and 0.3 million for the three months ended June 30, 2024 and 2023, respectively. Diluted common shares outstanding included common stock equivalents of 0.2 million for the six months ended June 30, 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.

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.

13

Unrealized gains for the nuclear decommissioning fund were $1.3 billion and $1.2 billion as of June 30, 2024 and Dec. 31, 2023, respectively, and unrealized losses were $40 million and $29 million as of June 30, 2024 and Dec. 31, 2023, respectively.

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

	June 30, 2024
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	43	$	43	$	—	$	—	$	—	$	43
Commingled funds	713		—		—		—		1,036		1,036
Debt securities	834		—		801		14		—		815
Equity securities	517		1,493		1		—		—		1,494
Total	$	2,107	$	1,536	$	802	$	14	$	1,036	$	3,388

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $251 million of equity method investments and $152 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 and six months ended June 30, 2024 and 2023, there were no transfers of Level 3 investments between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of June 30, 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	$	5	$	289	$	266	$	255	$	815

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 $94 million and $88 million at June 30, 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.

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 June 30, 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 June 30, 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 June 30, 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.

14

As of June 30, 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)	June 30, 2024	Dec. 31, 2023
Megawatt hours of electricity	75	48
Million British thermal units of natural gas	79	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 June 30, 2024, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $41 million, or 21%, 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 $64 million, or 33%, 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 $60 million, or 31%, 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 June 30, 2024 and Dec. 31, 2023, there were $17 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 June 30, 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 June 30, 2024 and Dec. 31, 2023.

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 June 30, 2024
Other derivative instruments:
Electric commodity	$	—	$	42
Natural gas commodity	—		(1)
Total	$	—	$	41
Six Months Ended June 30, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	29	$	—
Total	$	29	$	—
Other derivative instruments:
Electric commodity	$	—	$	41
Natural gas commodity	—		3
Total	$	—	$	44
Three Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	18	$	—
Total	$	18	$	—
Other derivative instruments:
Electric commodity	$	—	$	(19)
Total	$	—	$	(19)
Six Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	11	$	—
Total	$	11	$	—
Other derivative instruments:
Electric commodity	$	—	$	(111)
Natural gas commodity	—		3
Total	$	—	$	(108)

15

	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 June 30, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(14)	(b)
Electric commodity	—			(15)		(c)	—
Total	$	—		$	(15)		$	(14)
Six Months Ended June 30, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(22)	(b)
Electric commodity	—			(3)		(c)	—
Natural gas commodity	—			—			(14)		(d)(e)
Total	$	—		$	(3)		$	(36)
Three Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(6)	(b)
Electric commodity	—			11		(c)	—
Total	$	—		$	11		$	(6)
Six Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	3	(a)	$	—		$	—
Total	$	3		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(6)	(b)
Electric commodity	—			94		(c)	—
Natural gas commodity	—			10		(d)	(19)		(d)(e)
Total	$	—		$	104		$	(25)

(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 six months ended June 30, 2024 and 2023.

16

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

	June 30, 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	$	6	$	43	$	22	$	71	$	(51)	$	20	$	8	$	51	$	32	$	91	$	(59)	$	32
Electric commodity	—		—		211		211		(3)		208		—		—		62		62		(7)		55
Natural gas commodity	—		4		—		4		—		4		—		14		—		14		—		14
Total current derivative assets	$	6	$	47	$	233	$	286	$	(54)	232		$	8	$	65	$	94	$	167	$	(66)	101
PPAs (b)											2												3
Current derivative instruments											$	234											$	104
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	11	$	52	$	57	$	120	$	(36)	$	84	$	14	$	51	$	45	$	110	$	(34)	$	76
Total noncurrent derivative assets	$	11	$	52	$	57	$	120	$	(36)	$	84	$	14	$	51	$	45	$	110	$	(34)	$	76

	June 30, 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	$	6	$	77	$	6	$	89	$	(53)	$	36	$	6	$	86	$	5	$	97	$	(60)	$	37
Electric commodity	—		—		3		3		(3)		—		—		—		7		7		(7)		—
Natural gas commodity	—		1		—		1		—		1		—		12		—		12		—		12
Total current derivative liabilities	$	6	$	78	$	9	$	93	$	(56)	37		$	6	$	115	$	12	$	133	$	(67)	66
PPAs (b)											7												8
Current derivative instruments											$	44											$	74
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	14	$	56	$	42	$	112	$	(40)	$	72	$	16	$	50	$	37	$	103	$	(39)	$	64
Total noncurrent derivative liabilities	$	14	$	56	$	42	$	112	$	(40)	72		$	16	$	50	$	37	$	103	$	(39)	64
PPAs (b)											19												22
Noncurrent derivative instruments											$	91											$	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 June 30, 2024 and Dec. 31, 2023, derivative assets and liabilities include no obligations to return cash collateral. At June 30, 2024 and Dec. 31, 2023, derivative assets and liabilities include rights to reclaim cash collateral of $5 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.

17

Changes in Level 3 commodity derivatives:

	Three Months Ended June 30
(Millions of Dollars)	2024		2023
Balance at April 1	$	91	$	78
Purchases (a)	174		167
Settlements (a)	(110)		(47)
Net transactions recorded during the period:
Gains recognized in earnings (b)	3		10
Net gains recognized as regulatory assets and liabilities (a)	81		1
Balance at June 30	$	239	$	209
	Six Months Ended June 30
(Millions of Dollars)	2024		2023
Balance at Jan. 1	$	90	$	235
Purchases (a)	177		172
Settlements (a)	(161)		(76)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (b)	3		(2)
Net gains (losses) recognized as regulatory assets and liabilities (a)	130		(120)
Balance at June 30	$	239	$	209

(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 June 30, 2024, other financial instruments for which the carrying amount did not equal fair value:

	June 30, 2024				Dec. 31, 2023
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	28,570	$	24,959	$	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 June 30, 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 June 30
	2024		2023		2024		2023
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	19	$	18	$	1	$	—
Interest cost (a)	38		40		5		5
Expected return on plan assets (a)	(51)		(52)		(5)		(4)
Amortization of prior service credit (a)	(1)		—		—		—
Amortization of net loss (a)	8		5		—		1
Settlement charge (b)	56		—		—		—
Net periodic benefit cost	69		11		1		2
Effects of regulation	(40)		7		—		—
Net benefit cost recognized for financial reporting	$	29	$	18	$	1	$	2

	Six Months Ended June 30
	2024		2023		2024		2023
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	38	$	37	$	1	$	—
Interest cost (a)	76		80		10		11
Expected return on plan assets (a)	(103)		(105)		(9)		(9)
Amortization of prior service credit (a)	(1)		(1)		—		—
Amortization of net loss (a)	15		11		1		1
Settlement charge (b)	56		—		—		—
Net periodic benefit cost	81		22		3		3
Effects of regulation	(36)		14		—		—
Net benefit cost recognized for financial reporting	$	45	$	36	$	3	$	3

(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.

(b)A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the second quarter of 2024, as a result of lump-sum distributions during the 2024 plan year, Xcel Energy recorded a pension settlement charge of $56 million, of which $7 million was recognized in the consolidated statement of income after considering the effects of regulation.

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.

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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. 

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

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

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

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

Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (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 (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 307 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 4,087 plaintiffs. 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 filed before Jan. 1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

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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 — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which 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. According to the Texas A&M Forest Service’s Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.

SPS is aware of approximately 21 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’s 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 141 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 43 of those claims. In July 2024, SPS reached a settlement of a complaint related to one of the two fatalities believed to be associated with the Smokehouse Creek Fire Complex.

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 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 has accrued a $215 million estimated loss for the matter (before available insurance), presented in other current liabilities as of June 30, 2024.

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 remains 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. SPS has recorded an insurance receivable for $215 million, presented within prepayments and other current assets as of June 30, 2024. 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.

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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.

In May 2024, the ALJ recommended a customer refund of $34 million (less a portion of the proceeds received from the settlement with GE). The ALJ indicated that consideration of the $22 million of previously disallowed costs was not in the scope of their recommendation. Xcel Energy has recorded an estimate for a customer refund in this matter. A final decision by the MPUC is expected in late 2024.

Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC, with a proposed 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.

In May 2024, the DOC and Minnesota OAG filed comments relating to an outage at the Prairie Island generating station that lasted from October 2023 through February 2024. The DOC recommended that NSP-Minnesota refund $20 million of replacement power costs for 2023 as well as a future refund of replacement power costs for 2024 once those costs are known. The OAG recommended that NSP-Minnesota refund $18 million of replacement power costs for 2023 and did not address 2024.

In July 2024, NSP-Minnesota filed reply comments in the 2023 proceeding in support of its position that no customer refund for replacement power costs is warranted. A final decision by the MPUC is expected in late 2024.

Environmental

New and changing federal and state environmental mandates can create financial obligations 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 13 historical MGP, landfill or other disposal sites across its service territories, in addition to sites that are being addressed under current coal ash regulations (see below).

Xcel Energy has recognized approximately $20 million of costs/liabilities for resolution of these issues; however, the final outcomes 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.

Water and Waste

Coal Ash Regulation — Xcel Energy is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.

In May 2024, final amendments to the CCR Rule were published. These include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.

As a specific requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land, as well as perform corrective actions where offsite groundwater has been impacted.

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

Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-fueled generating facilities at a current estimated cost of at least $40 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. Asset retirement obligations have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.

Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-fueled generating facilities at estimated costs totaling approximately $100 million. Asset retirement obligations have been recorded, with the costs expected to be recoverable through regulatory mechanisms.

Xcel Energy continues to evaluate the 2024 updates to the CCR rule, the interpretations of those updates and how they will apply to specific sites. Assessment of the recent updates to the CCR Rule and corresponding site investigation activities may result in updates to estimated costs as well as identification of additional required corrective actions.

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.

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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. The rule took effect in NSP-Wisconsin in 2023 and 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.

In June 2024, the U.S. Supreme Court issued an order granting a stay of the final rule. We are assessing implementation of the stay order in Wisconsin.

Leases

Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space, land for solar developments 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 June 30
(Millions of Dollars)	2024		2023
Operating leases
PPA capacity payments	$	57	$	61
Other operating leases (a)	11		12
Total operating lease expense (b)	$	68	$	73
Finance leases
Amortization of ROU assets	$	1	$	—
Interest expense on lease liability	3		4
Total finance lease expense	$	4	$	4

(a)Includes short-term lease expense of $1 million and $3 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.

	Six Months Ended June 30
(Millions of Dollars)	2024		2023
Operating leases
PPA capacity payments	$	115	$	121
Other operating leases (a)	22		24
Total operating lease expense (b)	$	137	$	145
Finance leases
Amortization of ROU assets	$	2	$	1
Interest expense on lease liability	7		8
Total finance lease expense	$	9	$	9

(a)Includes short-term lease expense of $2 million and $5 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 June 30, 2024:

(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance  Leases (a)
Total minimum obligation	$	1,107	$	360	$	1,467	$	213
Interest component of obligation	(135)		(145)		(280)		(150)
Present value of minimum obligation	$	972	215		1,187		63
Less current portion					(226)		(2)
Noncurrent operating and finance lease liabilities					$	961	$	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.

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 June 30, 2024 and Dec. 31, 2023, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2041.

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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 June 30, 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 $79 million and $75 million at June 30, 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 June 30, 2024						Three Months Ended June 30, 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 April 1	$	(30)	$	(41)	$	(71)	$	(58)	$	(39)	$	(97)
Other comprehensive gain before reclassifications	—		—		—		13		—		13
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)	—		—		—		1		—		1
Amortization of net actuarial losses (b)	—		4		4		—		1		1
Net current period other comprehensive income	—		4		4		14		1		15
Accumulated other comprehensive loss at June 30	$	(30)	$	(37)	$	(67)	$	(44)	$	(38)	$	(82)

	Six Months Ended June 30, 2024						Six Months Ended June 30, 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 before reclassifications	22		—		22		8		—		8
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)	1		—		1		2		—		2
Amortization of net actuarial losses (b)	—		4		4		—		1		1
Net current period other comprehensive income	23		4		27		10		1		11
Accumulated other comprehensive loss at June 30	$	(30)	$	(37)	$	(67)	$	(44)	$	(38)	$	(82)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

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.

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Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services revenues/commissions, 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.

Xcel Energy had equity method investments of $251 million and $244 million as of June 30, 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 June 30
(Millions of Dollars)	2024		2023
Regulated Electric
Total revenues	$	2,659	$	2,601
Net income	353		350
Regulated Natural Gas
Total revenues	$	355	$	393
Net income (loss)	3		(22)
All Other
Total revenues	$	14	$	28
Net loss	(54)		(40)
Consolidated Total
Total revenues	$	3,028	$	3,022
Net income	302		288

	Six Months Ended June 30
(Millions of Dollars)	2024		2023
Regulated Electric
Operating revenues	$	5,344	$	5,364
Intersegment revenue	1		—
Total revenues	$	5,345	$	5,364
Net income	711		646
Regulated Natural Gas
Operating revenues	$	1,296	$	1,681
Intersegment revenue	1		2
Total revenues	$	1,297	$	1,683
Net income	161		137
All Other
Total revenues	$	37	$	57
Net loss	(82)		(77)
Consolidated Total
Total revenues	$	6,679	$	7,104
Reconciling eliminations	(2)		(2)
Total operating revenues	$	6,677	$	7,102
Net income	790		706

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.

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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 and six months ended June 30, 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.

Summarized diluted EPS for Xcel Energy:

	Three Months Ended June 30				Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2024		2023		2024		2023
NSP-Minnesota	$	0.24	$	0.23	$	0.61	$	0.48
PSCo	0.21		0.17		0.61		0.56
SPS	0.16		0.15		0.26		0.25
NSP-Wisconsin	0.04		0.05		0.12		0.13
Earnings from equity method investments — WYCO	0.01		0.01		0.02		0.02
Regulated utility	0.66		0.60		1.62		1.43
Xcel Energy Inc. and Other	(0.12)		(0.08)		(0.20)		(0.15)
GAAP diluted EPS	$	0.54	$	0.52	$	1.42	$	1.28

Summary of Earnings

Xcel Energy — Xcel Energy’s second quarter GAAP and ongoing diluted earnings were $0.54 per share, compared with $0.52 per share in the same period in 2023. The increase in earnings per share was primarily driven by increased recovery of infrastructure investments and warmer than normal weather, partially offset by higher depreciation, interest charges and O&M expenses. 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).

NSP-Minnesota — GAAP and ongoing earnings increased $0.01 per share for the second quarter and $0.13 year-to-date. Year-to-date earnings primarily reflect increased recovery of electric and natural gas infrastructure investments and lower O&M expenses, partially offset by higher depreciation.

PSCo — GAAP and ongoing earnings increased $0.04 in the second quarter and $0.05 year-to-date. The year-to-date change was driven by increased recovery of electric infrastructure investments, which was partially offset by increased depreciation.

SPS — GAAP and ongoing earnings increased $0.01 for the second quarter and year-to-date as regulatory rate outcomes and increased sales and demand were partially offset by increased depreciation.

NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 in the second quarter and year-to-date, largely due to unfavorable weather and increased depreciation.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings is largely due to increased interest rates and higher debt levels.

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 June 30		Six Months Ended June 30
GAAP and ongoing diluted EPS — 2023	$	0.52	$	1.28
Components of change - 2024 vs. 2023
Electric regulatory rate outcomes (a)	0.26		0.40
Higher AFUDC	0.04		0.08
Natural gas regulatory rate outcomes (b)	0.02		0.05
(Higher) lower O&M expenses	(0.04)		0.02
Higher depreciation and amortization	(0.18)		(0.23)
Higher interest charges	(0.07)		(0.12)
Other, net	(0.01)		(0.06)
GAAP and ongoing diluted EPS — 2024	$	0.54	$	1.42

(a)Includes the revenue impact of regulatory rate outcomes and non-fuel riders.

(b)Includes the revenue impact of natural gas regulatory rate outcomes and infrastructure and integrity riders.

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.

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

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

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

Percentage increase (decrease) in normal and actual HDD, CDD and THI:

	Three Months Ended June 30						Six Months Ended June 30
	2024 vs. Normal		2023 vs. Normal		2024 vs. 2023		2024 vs. Normal		2023 vs. Normal		2024 vs. 2023
HDD	(21.4)	%	(9.5)	%	(15.3)	%	(13.2)	%	(0.7)	%	(13.0)	%
CDD	36.8		(26.3)		84.6		36.5		(27.1)		85.3
THI	(37.6)		44.6		(55.0)		(37.7)		44.2		(54.9)

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

	Three Months Ended June 30						Six Months Ended June 30
	2024 vs. Normal		2023 vs. Normal		2024 vs. 2023		2024 vs. Normal		2023 vs. Normal		2024 vs. 2023
Retail electric	$	0.006	$	0.001	$	0.005	$	(0.023)	$	0.003	$	(0.026)
Decoupling and sales true-up	0.025		(0.017)		0.042		0.041		(0.023)		0.064
Electric total	$	0.031	$	(0.016)	$	0.047	$	0.018	$	(0.020)	$	0.038
Firm natural gas	(0.011)		(0.003)		(0.008)		(0.038)		0.026		(0.064)
Decoupling	0.002		—		0.002		0.019		—		0.019
Natural gas total	$	(0.009)	$	(0.003)	$	(0.006)	$	(0.019)	$	0.026	$	(0.045)
Total	$	0.022	$	(0.019)	$	0.041	$	(0.001)	$	0.006	$	(0.007)

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

	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	12.1	%	(10.9)	%	11.7	%	(6.2)	%	0.4	%
Electric C&I	(0.8)		(5.8)		6.9		(3.4)		(0.4)
Total retail electric sales	3.2		(7.4)		7.5		(4.1)		(0.2)
Firm natural gas sales	(9.7)		(10.9)		N/A		(9.5)		(10.1)

	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(0.3)	%	1.0	%	(0.2)	%	(1.2)	%	0.2	%
Electric C&I	(4.1)		(3.6)		6.2		(2.5)		(0.8)
Total retail electric sales	(2.9)		(2.2)		5.2		(2.2)		(0.5)
Firm natural gas sales	(4.4)		(0.6)		N/A		(3.6)		(3.2)

	Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	4.2	%	(8.3)	%	4.2	%	(6.8)	%	(1.9)	%
Electric C&I	(0.2)		(4.5)		7.2		(2.6)		0.3
Total retail electric sales	1.2		(5.7)		6.6		(3.8)		(0.3)
Firm natural gas sales	(9.3)		(13.6)		N/A		(13.4)		(10.9)

	Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	0.3	%	—	%	(1.7)	%	(2.2)	%	(0.3)	%
Electric C&I	(1.5)		(2.9)		6.8		(2.0)		0.4
Total retail electric sales	(0.9)		(2.0)		5.3		(2.1)		0.2
Firm natural gas sales	2.2		0.8		N/A		(3.2)		1.4

	Six Months Ended June 30 (Leap Year Adjusted)
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(0.3)	%	(0.6)	%	(2.4)	%	(2.8)	%	(0.9)	%
Electric C&I	(2.1)		(3.5)		6.2		(2.5)		(0.1)
Total retail electric sales	(1.5)		(2.6)		4.7		(2.6)		(0.4)
Firm natural gas sales	1.3		(0.2)		N/A		(4.1)		0.4

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

•PSCo — Residential sales decreased due to a 1.6% 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 manufacturing, information and real estate sectors.

•NSP-Minnesota — Residential sales decreased due to a 2.1% 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 2.9% 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 3.6% 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.

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

•Increase in natural gas sales was driven by residential and C&I customer growth in all jurisdictions and increased use per customer in PSCo. 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.

(Millions of Dollars)	Three Months Ended June 30, 2024 vs. 2023		Six Months Ended June 30, 2024 vs. 2023
Recovery of lower cost of electric fuel and purchased power	$	(155)	$	(331)
Wholesale generation revenues	(13)		(31)
PTCs flowed back to customers (offset by lower ETR)	(3)		(12)
Sales and demand (a)	(25)		(10)
Regulatory rate outcomes (MN, CO, TX, NM, & WI)	159		225
Non-fuel riders	36		70
Conservation and demand side management (offset in expense)	23		43
Revenue recognition for the Texas rate case surcharge (b)	37		37
Estimated impact of weather (net of sales true-up)	34		27
Other, net	(35)		(38)
Total increase (decrease)	$	58	$	(20)

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

(b)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.

Natural Gas Revenues

Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.

(Millions of Dollars)	Three Months Ended June 30, 2024 vs. 2023		Six Months Ended June 30, 2024 vs. 2023
Recovery of lower cost of natural gas	$	(51)	$	(410)
Estimated impact of weather (net of decoupling)	(4)		(33)
Regulatory rate outcomes	13		35
Retail sales growth (net of decoupling)	(1)		9
Infrastructure and integrity riders	2		5
Other, net	3		9
Total decrease	$	(38)	$	(385)

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. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Electric fuel and purchased power expenses decreased $175 million for the second quarter and $344 million year-to-date. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices.

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 largely offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $52 million for the second quarter and $413 million year-to-date. The decrease is primarily due to lower commodity prices and volumes.

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $34 million for the second quarter and decreased $11 million year-to-date. The year-to-date decrease was primarily due to decreased labor and benefit costs, gain on a land sale in the first quarter and lower bad debt expenses, partially offset by recognition of previously deferred costs associated with the Texas Electric Rate Case and planned generation outages that both occurred in the second quarter, as well as increased wildfire mitigation costs.

Depreciation and Amortization — Depreciation and amortization increased $138 million for the second quarter and $172 million year-to-date. The year-to-date increase was largely the result of system expansion as well as recognition of previously deferred costs and depreciation rate changes associated with the Texas Rate Case, partially offset by wind and nuclear life extensions implemented in 2023 in the Minnesota Electric Rate Case.

Interest Charges — Interest charges increased $51 million for the second quarter and $89 million year-to-date, largely due to increased debt levels and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $24 million for the second quarter and $46 million year-to-date, driven by increased investment in renewable and transmission projects.

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.

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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 a 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).

In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms:

•Natural gas rate increase of $46 million, or 7.5%.

•ROE of 9.6%.

•Equity ratio of 52.5%.

•Rate base of $1.25 billion.

•No change to Commission approved decoupling.

A MPUC decision and order is expected by the end of 2024.

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%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.

In June 2024, the North Dakota staff filed testimony and recommended a $6.3 million increase (7%), based on a ROE of 9.8% and a 50% equity ratio.

The procedural schedule is as follows:

•Surrebuttal testimony: Aug. 12-26, 2024

•Evidentiary hearings: Sept. 3-5, 2024

A NDPSC decision is expected by year-end.

2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.

In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.

In November 2023, NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals. In June 2024, a group of Minnesota utilities filed an amicus brief supporting NSP-Minnesota’s position related to prepaid pension assets. The appeal is pending a court decision.

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-Wisconsin

Pending Regulatory Proceedings

Michigan Electric Rate Case — In July 2024, NSP-Wisconsin filed a Michigan electric rate case, seeking a $2.9 million (16.7%) rate increase for 2025, based on a ROE of 10.0% and an equity ratio of 52%. In addition, NSP-Wisconsin proposed an Investment Recovery Mechanism which would result in increases of $2.0 million (9.8%) in 2026 and $0.8 million (3.7%) in 2027 for recovery of costs associated with distribution and generation investment. A decision is expected in the first half of 2025.

Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. The filing proposes to offset $28 million and $3 million of the Company’s forecasted 2025 electric and natural gas revenue deficiency, respectively, by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two gas capital projects. The Company expects to have a Commission decision before year-end 2024.

NSP System

2022 Upper Midwest IRP Resource Acquisition — NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the approved Upper Midwest 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 650 MW of solar and/or solar plus storage development assets to replace the capacity from the retiring King Generating Station. NSP-Wisconsin did not accept any bids from the RFP and continues to pursue projects to meet this capacity need, including through the July 2024 RFP.

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

•In June and July 2024, respectively, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System. Among other things, the RFP will seek to reutilize interconnection rights associated with the retiring Sherco and King coal units in NSP-Minnesota. Dependent on the proposals received, NSP-Minnesota or NSP-Wisconsin plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second quarter of 2025.

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.

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These proposed resources are in addition to projects already approved by the MPUC. NSP-Minnesota anticipates a MPUC decision in 2025 and will file related RFPs upon approval.

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 (9.5%). The request is based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year 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 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.

In July 2024, three intervenors filed testimony, with Staff and the UCA filing comprehensive testimony. Staff and UCA opposed the deferral of collections until Feb. 15, 2025, instead proposing Nov. 1, 2024 as the effective date for new rates.

Proposed modifications:

(Millions of Dollars)	Staff				UCA
PSCo Direct Testimony	$	171			$	171
Recommended adjustments:
ROE	(40)				(31)
Capital structure and cost of capital	(27)			(a)	(14)
Test year adjustments to reflect average vs. year-end balances	(19)				(17)
Capital adjustments (subject to separate review)	(3)				(1)
Depreciation expense	15				—
Other, net	(4)				(17)
Total adjustments	(78)				(80)
Proposed revenue change	$	93			$	91
ROE	8.89		%		9.20		%
Equity ratio	52		%		51.4		%
Test Year	Dec 2023				Dec 2023
Rate Base Convention	13 month				13 month

(a) Revised estimate.

Procedural schedule:

•Rebuttal testimony: Aug. 15, 2024

•Settlement deadline: Aug. 27, 2024

•Evidentiary hearing: Sept. 4-12, 2024

•Statement of position: Sept. 26, 2024

A CPUC decision is expected in the fourth quarter of 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.

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

PSCo filed or expects to file generation and transmission certificates of public convenience and necessity throughout 2024.

PSCo will file an interim resource plan, also referred to as the Just Transition Solicitation, by Oct. 15, 2024. The filing deadline was extended to Oct. 15, 2024 to allow for additional time to assess the impact of supply chain issues and solar tariffs on the Colorado Resource Plan portfolio.

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.

Wildfire Mitigation Plan — In June 2024, PSCo filed an Updated Wildfire Mitigation Plan (the Plan) and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion. A CPUC decision is expected in early 2025.

The Plan is a key component of keeping our customers and communities safe while providing reliable and affordable electric service. The Plan integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following:

•Situational awareness – Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring.

•Operational mitigations – Enhanced powerline safety settings and PSPS.

•System resiliency – Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management.

•Customer support – Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates.

Total capital investments and O&M expenses associated with the proposed plan are estimated at the following:

(Millions of Dollars)	2025		2026		2027		Total
Capital investments
Situational awareness	$	24	$	17	$	10	$	51
Operational mitigations	58		66		83		207
System resiliency	368		411		565		1,344
Total capital investments	$	450	$	494	$	658	$	1,602
O&M expenses
Situational awareness	$	9	$	10	$	10	$	29
Operational mitigations	3		3		4		10
System resiliency	44		69		77		190
Customer support	7		8		9		24
Total O&M expenses	63		90		100		253
Total expenditures	$	513	$	584	$	758	$	1,855

CPUC Proactive Line De-Energization Investigation — In April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 MPH to reduce potential wildfire risk.

In May 2024, the CPUC held sessions to hear public comments and Commissioner Information Meetings on the impacts of the power shutoffs. PSCo has provided responses to CPUC information requests and will continue to respond to requests throughout 2024 as the investigation continues.

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Clean Heat Plan — In August of 2023, PSCo filed a Clean Heat Plan to reduce natural gas local distribution company greenhouse gas emissions. PSCo proposed a diversified portfolio of electrification, efficiency and lower-carbon gas options that would create an emissions reduction pathway through 2028 consistent with achieving a 2030 target reduction of 22 percent.

In June 2024, the CPUC approved a portfolio weighted predominantly toward electrification and efficiency programs, based on a budget of $441 million through 2027. The CPUC’s approval included rider cost recovery. The CPUC directed PSCo to file the next Clean Heat Plan in 2026.

Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 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 plan to manage customer bill volatility from commodity price changes, 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. The CPUC issued a written notice of the proposed rule in the second quarter of 2024 and held a hearing on comments in July 2024. A CPUC decision and final rule is expected later in 2024. The Commission's proposed rules for electric utilities are also expected later in 2024.

Colorado Senate Bill 24-218 — In May 2024, Colorado Senate Bill 24-218 was signed into law. The bill includes a suite of policy changes to accelerate investment in electric distribution, including a framework to develop distribution planning and performance requirements and the opportunity for current cost recovery for many distribution investments. In July 2024, the CPUC approved PSCo’s request to collect $17 million through a rider, over the remainder of 2024, subject to true-up, associated with forecasted capital investments covered by the new legislation.

Cabin Creek Prudency Review — In 2015, the CPUC granted a CPCN for an $88 million upgrade project to renew the FERC operating license and increase the generating and storage capacity of the Cabin Creek hydroelectric storage facility, which anticipated project completion in 2020. Due to significant and unforeseen challenges, the project was not completed until 2023 and cost approximately $110 million. In July 2024, PSCo filed a prudency review for the upgrade project, which reviews the project’s timelines, costs, benefits and challenges. A procedural schedule is expected in the third quarter of 2024 with a final CPUC decision in 2025.

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%). Interim rates went into effect on Feb. 1, 2024. In April 2024, the PUCT approved a black box settlement between SPS and intervening parties, which reflect the following terms:

•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’ AFUDC 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.

In July 2024, SPS filed to surcharge the final under-recovered amount, estimated to be $37 million. This will be largely offset by previously deferred costs including depreciation, O&M, and taxes other than income tax.

2022 All-Source RFP — In July 2023, SPS filed for approval of a CPCN for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. The NMPRC approved the projects in May 2024. In July 2024, the PUCT approved the solar projects and denied the battery project. The PUCT’s approval included minimum production and PTC guarantees.

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. The NMPRC approved the PPA agreements in June and a PUCT decision is expected in the fourth quarter of 2024.

New Mexico Resource Plan (IRP) — 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. SPS’ initial IRP modeling projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP.

In July 2024, SPS issued a RFP, seeking approximately 3,000 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the approximate range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.

The RFP will be evaluated in the first quarter of 2025. SPS is expected to file for a certificate of need for the recommended portfolio in the summer of 2025. The Texas and New Mexico Commissions are expected to rule on the recommended portfolio in 2026.

Texas DCRF — In May 2024, SPS filed for a DCRF to recover $13 million through a rider for distribution capital investment placed in service for the year ended December 31, 2023. SPS’ requested DCRF rates went into effect in late July 2024.

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Other

Supply Chain

Xcel Energy’s ability to meet customer energy requirements, execute our capital expenditure program and respond to storm-related disruptions 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.

Large global demand for energy-related infrastructure (renewables and gas generation, data centers, etc.) has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.

Tariffs and Trade Complaints

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 remained 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.

In April 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.

In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells, whether or not assembled into modules. A preliminary decision related to this matter is anticipated in November 2024.

In June 2024, a previous tariff exclusion for bi-facial panels ended. Tariff rate is now 14.25% until February 2025 and 14% until February 2026 for imported panels.

In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.

Xcel Energy continues to assess the impacts of these tariffs and trade complaints on its business, including company-owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.

Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs.

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. Based on current estimates and assumptions, Xcel Energy has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements 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, Red Wing Generating Plant and Wilmarth Generating Plant. 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.

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.

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In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA. In July 2024, the EPA’s final rule went into effect.

In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals. In June 2024, the EPA’s final rule went into effect.

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

Potential costs are uncertain and will be determined on a site specific basis where applicable. If costs are incurred, Xcel Energy believes the costs will be recoverable through rates based on prior state commission practices.

Effluent Limitation Guidelines

In April 2024, the EPA published final rules under the Clean Water Act, setting 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. Based on current estimates and assumptions, Xcel Energy has determined that there is minimal financial or operational impact associated with these requirements and that any costs 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.

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 June 30, 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)	$	(1)	$	(4)	$	(2)	$	—	$	(7)
NSP- Minnesota (b)	(15)		(7)		(7)		2		(27)
PSCo (a)	—		2		1		—		3
PSCo (b)	(3)		4		2		—		3
	$	(19)	$	(5)	$	(6)	$	2	$	(28)

	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	$	5	$	18
	$	—	$	—	$	13	$	5	$	18

(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 six months ended June 30:

(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	(2)		—
Commodity trading contract additions and changes during the period	(9)		33
Fair value of commodity trading net contracts outstanding at June 30	$	(10)	$	—

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 $3 million and $5 million at June 30, 2024 and June 30, 2023, respectively.

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 June 30		Average		High		Low
2024	$	—	$	1	$	1	$	—
2023	1		1		1		—

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Nuclear Fuel Supply — In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota will no longer be permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. NSP-Minnesota has secured its enriched nuclear material requirements through 2029 with non-Russian material, which are in various stages of processing in Canada, Europe and the United States. NSP-Minnesota continues to assess the impacts of this legislation on its existing contracts related to Russian-sourced nuclear material.

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 $5 million in June 30, 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 June 30, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $42 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $40 million. At June 30, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $47 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $46 million.

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)	Six Months Ended June 30
Cash provided by operating activities — 2023	$	2,455
Components of change — 2024 vs. 2023
Higher net income	84
Non-cash transactions	131
Changes in deferred income taxes	477
Changes in working capital	(547)
Changes in net regulatory and other assets and liabilities	(360)
Cash provided by operating activities — 2024	$	2,240

Net cash provided by operating activities decreased $215 million for the six months ended June 30, 2024 compared with the prior year. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, 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)	Six Months Ended June 30
Cash used in investing activities — 2023	$	(2,639)
Components of change — 2024 vs. 2023
Increased capital expenditures	(769)
Other investing activities	5
Cash used in investing activities — 2024	$	(3,403)

Net cash used in investing activities increased $764 million for the six months ended June 30, 2024 compared with the prior year. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.

Financing Cash Flows

(Millions of Dollars)	Six Months Ended June 30
Cash provided by financing activities — 2023	$	348
Components of change — 2024 vs. 2023
Lower net short-term repayments	286
Higher long-term debt issuances, net of repayments	2,003
Higher proceeds from issuance of common stock	24
Other financing activities	(29)
Cash provided by financing activities — 2024	$	2,632

Net cash provided by financing activities increased $2,284 million for the six months ended June 30, 2024 compared with the prior year. The increase was largely related to additional debt issuances to fund capital investment and the repayment of maturing debt issuances.

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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.

As of July 30, 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	$	792	$	708	$	2	$	710
PSCo	700		31		669		602		1,271
NSP-Minnesota	700		12		688		129		817
SPS	500		—		500		252		752
NSP-Wisconsin	150		—		150		178		328
Total	$	3,550	$	835	$	2,715	$	1,163	$	3,878

(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 June 30, 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 Financing Activity — Xcel Energy and its utility subsidiaries issued the following long-term debt:

Issuer	Security	Amount			Tenor	Coupon
Xcel Energy Inc.	Senior Unsecured Notes	$	800	million	10 Year	5.50	%
NSP-Minnesota	First Mortgage Bonds	700		million	30 Year	5.40
PSCo	First Mortgage Bonds	1,200		million	10 Year & 30 Year	5.35 & 5.75
SPS	First Mortgage Bonds	600		million	30 Year	6.00
NSP-Wisconsin	First Mortgage Bonds	400		million	30 Year	5.65

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.

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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%.

•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 $305 million to $315 million.

•Property taxes are projected to be flat. This change is largely earnings neutral and is offset in revenue due to property tax trackers.

•Interest expense (net of AFUDC - debt) is projected to increase $140 million to $150 million, net of interest income.

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

•ETR is projected to be ~(6%) to (8%). The assumption change is largely due to an increase in the PTC rate, which is offset in revenue and largely earnings neutral. The negative ETR is largely offset by PTCs flowing back to customers in 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.

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 June 30, 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

Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.

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

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

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

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.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:

For the quarter ended June 30, 2024, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.

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 June 30, 2024.

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 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
4.02*	Supplemental Indenture dated as of May 13, 2024 between Northern States Power Company and U.S. Bank Trust Company, National Association, as successor Trustee, creating $400 million principal amount of 5.65% First Mortgage Bonds, Series due June 15, 2054	NSP-Wisconsin Form 8-K dated May 16, 2024	4.01
4.03*	Supplemental Indenture No. 11 dated as of May 15, 2024 between Southwestern Public Service Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $600 million principal amount of 6.00% First Mortgage Bonds, Series No. 11 due 2054	SPS Form 8-K dated June 6, 2024	4.02
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.
8/1/2024	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)

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