UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, ~~2023~~2024


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

For the transition period from to

Commission File Number: 001-3034


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

Minnesota

41-0448030

(State or Other Jurisdiction of Incorporation or Organization)

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

414 Nicollet Mall

Minneapolis

Minnesota

55401

(Address of Principal Executive Offices)

(Zip Code)


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


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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $2.50 par value

XEL

Nasdaq Stock Market LLC

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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


Class						Outstanding at April ~~24, 2023~~22, 2024
Common Stock, $2.50 par value						~~550,356,331~~555,639,439 shares

TABLE OF CONTENTS


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	5
	Consolidated Statements of Income	5
	Consolidated Statements of Comprehensive Income	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Common Stockholders’ Equity	9
	Notes to Consolidated Financial Statements	10
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2022
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	3031
Item 4 —	Controls and Procedures	3032

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	3032
Item 1A —	Risk Factors	3032
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	3132
Item 5 —	Other Information	32
Item 6 —	Exhibits	3133

SIGNATURES		3234

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

Definitions of Abbreviations


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


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

~~LES-FEA~~			~~Louisiana Energy Services & Federal Executive Agencies~~
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


~~Electric, Purchased Gas and Resource Adjustment Clauses~~
~~ECA~~SDPUC			~~Retail electric commodity adjustment~~
~~GCA~~			~~Gas cost adjustment~~South Dakota Public Utilities Commission


Other
AFUDC			Allowance for funds used during construction
AG			~~New Mexico Attorney General~~
ALJ			Administrative Law Judge

ATM			At-the-market

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


CEO			Chief executive officer


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

FTR			Financial transmission right
~~FTY~~			~~Future test year~~
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~~IRP			~~Inflation Reduction Act~~Integrated Resource Plan
~~LDC~~			~~Local distribution company~~

LLC			Limited liability company
LP&L			Lubbock Power and Light
MGP			Manufactured gas plant
MPH			Miles per hour
MISO			Midcontinent Independent System Operator, Inc.
NAV			Net asset value
~~NMLCG~~			~~New Mexico Large Customer Group~~
~~NOPR~~			~~Notice of Proposed Rulemaking~~
NOx			Nitrogen Oxides
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
~~OPL~~			~~Occidental Permian Ltd.~~
PFAS			Per- and ~~Polyfluroroalkyl~~Polyfluoroalkyl Substances
PIM			Performance ~~Incentive Mechanism~~incentive mechanism
PPA			Power purchase agreement
PTC			Production tax credit
RFP			Request for proposal
ROE			Return on equity
RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.

~~TCA~~TEP			~~Transmission cost adjustment~~Transportation electrification plan

THI			Temperature-humidity index
~~TOs~~			~~Transmission owners~~

VaR			Value at Risk
WACC			Weighted average cost of capital


Measurements
MW			Megawatts


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to ~~2023~~2024 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed ~~elsewhere~~ in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2022~~2023 and subsequent filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee ~~work force~~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; ~~cyber security~~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;~~penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.

Table of Contents

PART I — FINANCIAL INFORMATION


ITEM 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in millions, except per share data)

Three Months Ended March 31

2023

2022

Three Months Ended March 31

2024

Operating revenues

Electric

2,763

2,633

Electric

Natural gas

1,288

1,090

Other

Total operating revenues

4,080

3,751

Operating expenses

Electric fuel and purchased power

1,117

1,094

Cost of natural gas sold and transported

844

710

Cost of natural gas sold and transported

Cost of sales — other

Operating and maintenance expenses

650

602

Operating and maintenance expenses

Conservation and demand side management expenses

Depreciation and amortization

624

562

Depreciation and amortization

Taxes (other than income taxes)

184

171

Taxes (other than income taxes)

Total operating expenses

3,507

3,241

Operating income

573

510

Operating income

Other income, net

Earnings from equity method investments

Allowance for funds used during construction — equity

Interest charges and financing costs

Interest charges — includes other financing costs of $8

253

214

Interest charges and financing costs

Interest charges — includes other financing costs

Allowance for funds used during construction — debt

(10)

(5)

Allowance for funds used during construction — debt

Total interest charges and financing costs

243

209

Income before income taxes

365

330

Income before income taxes

Income tax benefit

(53)

(50)

Income tax benefit

Net income

418

380

Weighted average common shares outstanding:

Basic

551

545

Basic

Diluted

551

545

Earnings per average common share:

Basic

0.76

0.70

Basic

Diluted

0.76

0.70

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in millions)

Three Months Ended March 31

2024

Net income

Other comprehensive income

Three Months Ended March 31

2023

2022

Net income

418

380

Other comprehensive income

Pension and retiree medical benefits:

Derivative instruments:

Reclassifications of loss to net income, net of tax of $— and $1, respectively

—

Derivative instruments:

Net fair value (decrease) increase, net of tax of $(2) and $1, respectively

(5)

Reclassification of losses to net income, net of tax of $— and $1, respectively

Total other comprehensive (loss) income

(4)

Derivative instruments:

Net fair value increase (decrease), net of tax

Reclassification of losses to net income, net of tax

Total other comprehensive income (loss)

Total comprehensive income

414

387

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in millions)


		Three Months Ended March 31					Three Months Ended March 31
		2023		2022			2024	2023
Operating activities	Operating activities
Net income	Net income	$	418	$	380
Net income
Net income
Adjustments to reconcile net income to cash provided by operating activities:	Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization
Depreciation and amortization
Depreciation and amortization	Depreciation and amortization	631		567
Nuclear fuel amortization	Nuclear fuel amortization	29		30
Deferred income taxes	Deferred income taxes	(73)		(55)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(19)		(13)
Earnings from equity method investments	Earnings from equity method investments	(11)		(15)
Dividends from equity method investments	Dividends from equity method investments	9		10
Provision for bad debts	Provision for bad debts	23		17
Share-based compensation expense	Share-based compensation expense	9		4
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:
Accounts receivable
Accounts receivable
Accounts receivable	Accounts receivable	50		(191)
Accrued unbilled revenues	Accrued unbilled revenues	329		146
Inventories	Inventories	189		107
Other current assets	Other current assets	8		(10)
Accounts payable	Accounts payable	(359)		(34)
Net regulatory assets and liabilities	Net regulatory assets and liabilities	345		215
Other current liabilities	Other current liabilities	63		51
Pension and other employee benefit obligations	Pension and other employee benefit obligations	(45)		(31)
Other, net	Other, net	(59)		(38)
Net cash provided by operating activities	Net cash provided by operating activities	1,537		1,140

Investing activities	Investing activities
Investing activities
Investing activities
Capital/construction expenditures
Capital/construction expenditures
Capital/construction expenditures	Capital/construction expenditures	(1,265)		(942)
Purchase of investment securities	Purchase of investment securities	(236)		(156)
Proceeds from the sale of investment securities	Proceeds from the sale of investment securities	228		147
Other, net	Other, net	(11)		(1)
Net cash used in investing activities	Net cash used in investing activities	(1,284)		(952)

Financing activities	Financing activities
Proceeds from (repayments of) short-term borrowings, net		266		(9)

Financing activities
Financing activities
Repayments of short-term borrowings, net
Repayments of short-term borrowings, net
Repayments of short-term borrowings, net
Proceeds from issuances of long-term debt
Repayments of long-term debt, including reacquisition premiums	Repayments of long-term debt, including reacquisition premiums	(250)		—
Proceeds from issuance of common stock	Proceeds from issuance of common stock	6		1
Dividends paid	Dividends paid	(259)		(240)
Other, net	Other, net	(13)		(16)
Net cash used in financing activities		(250)		(264)
Net cash provided by (used in) financing activities

Net change in cash, cash equivalents and restricted cash
Net change in cash, cash equivalents and restricted cash
Net change in cash, cash equivalents and restricted cash	Net change in cash, cash equivalents and restricted cash	3		(76)
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	111		166
Cash, cash equivalents and restricted cash at end of period	Cash, cash equivalents and restricted cash at end of period	$	114	$	90

Supplemental disclosure of cash flow information:	Supplemental disclosure of cash flow information:
Supplemental disclosure of cash flow information:
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	Cash paid for interest (net of amounts capitalized)	$	(209)	$	(202)
Cash paid for income taxes, net		(1)		—
Cash paid for interest (net of amounts capitalized)
Cash paid for interest (net of amounts capitalized)
Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers

Supplemental disclosure of non-cash investing and financing transactions:	Supplemental disclosure of non-cash investing and financing transactions:
Supplemental disclosure of non-cash investing and financing transactions:
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions
Accrued property, plant and equipment additions
Accrued property, plant and equipment additions	Accrued property, plant and equipment additions	$	449	$	288
Inventory transfers to property, plant and equipment	Inventory transfers to property, plant and equipment	34		20
Operating lease right-of-use assets	Operating lease right-of-use assets	47		8
Allowance for equity funds used during construction	Allowance for equity funds used during construction	19		13
Issuance of common stock for reinvested dividends and/or equity awards	Issuance of common stock for reinvested dividends and/or equity awards	21		11
						See Notes to Consolidated Financial Statements
See Notes to Consolidated Financial Statements

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in millions, except share and per share ~~data)~~

March 31, 2023 Dec. 31, 2022
Assets
Current assets
Cash and cash equivalents $ 114 $ 111
Accounts receivable, net 1,300 1,373
Accrued unbilled revenues 777 1,105
Inventories 580 803
Regulatory assets 983 1,059
Derivative instruments 97 279
Prepaid taxes 43 54
Prepayments and other 359 360
Total current assets 4,253 5,144
Property, plant and equipment, net 48,896 48,253
Other assets
Nuclear decommissioning fund and other investments 3,373 3,234
Regulatory assets 2,657 2,871
Derivative instruments 97 93
Operating lease right-of-use assets 1,194 1,204
Other 475 389
Total other assets 7,796 7,791
Total assets $ 60,945 $ 61,188
Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 901 $ 1,151
Short-term debt 1,079 813
Accounts payable 1,338 1,804
Regulatory liabilities 358 418
Taxes accrued 682 569
Accrued interest 242 217
Dividends payable 286 268
Derivative instruments 62 76
Operating lease liabilities 224 217
Other 489 545
Total current liabilities 5,661 6,078
Deferred credits and other liabilities
Deferred income taxes 4,729 4,756
Deferred investment tax credits 47 48
Regulatory liabilities 5,640 5,569
Asset retirement obligations 3,423 3,380
Derivative instruments 116 113
Customer advances 180 181
Pension and employee benefit obligations 345 390
Operating lease liabilities 1,020 1,038
Other 148 147
Total deferred credits and other liabilities 15,648 15,622
Commitments and contingencies
Capitalization
Long-term debt 22,818 22,813
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 550,222,192 and 549,578,018 shares outstanding at March 31, 2023 and December 31, 2022, respectively 1,376 1,374
Additional paid in capital 8,169 8,155
Retained earnings 7,370 7,239
Accumulated other comprehensive loss (97) (93)
Total common stockholders’ equity 16,818 16,675
Total liabilities and equity $ 60,945 $ 61,188
See Notes to Consolidated Financial Statements
data


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

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

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

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

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

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

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

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


	Common Stock Issued																		Common Stock Issued		Retained Earnings	Accumulated Other Comprehensive Loss	Total Common Stockholders' Equity
	Shares
Three Months Ended March 31, 2024 and 2023
Three Months Ended March 31, 2024 and 2023
Three Months Ended March 31, 2024 and 2023
Balance at Dec. 31, 2022
Balance at Dec. 31, 2022
Balance at Dec. 31, 2022
Net income
Other comprehensive loss
Dividends declared on common stock ($0.52 per share)
Issuances of common stock

Share-based compensation
Share-based compensation
Share-based compensation
Balance at March 31, 2023

Balance at Dec. 31, 2023
Balance at Dec. 31, 2023
Balance at Dec. 31, 2023
Net income
Other comprehensive income
Dividends declared on common stock ($0.5475 per share)
Issuances of common stock

Share-based compensation
Share-based compensation
Share-based compensation
Balance at March 31, 2024

		Common Stock Issued					Retained Earnings			Accumulated Other Comprehensive Loss				Total Common Stockholders' Equity
See Notes to Consolidated Financial Statements
		Shares	Par Value		Additional Paid In Capital				Retained Earnings							Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
Three Months Ended March 31, 2023 and 2022
Balance at Dec. 31, 2021		544,025,269	$	1,360	$	7,803	$	6,572				$	(123)			$	15,612
Net income							380							380
Other comprehensive loss										7				7
Dividends declared on common stock ($0.4875 per share)							(265)							(265)
Issuances of common stock		505,718	1		11									12

Share-based compensation					(13)		(1)							(14)

Balance at March 31, 2022		544,530,987	$	1,361	$	7,801	$	6,686		$	(116)			$	15,732

Balance at Dec. 31, 2022		549,578,018	$	1,374	$	8,155	$	7,239		$	(93)			$	16,675
Net income							418							418
Other comprehensive income										(4)				(4)
Dividends declared on common stock ($0.52 per share)							(286)							(286)
Issuances of common stock		644,174	2		16									18

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

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of March 31, ~~2023~~2024 and Dec. 31, ~~2022;~~2023; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, cash flows and changes in stockholders’ equity for the three months ended March 31, ~~2023~~2024 and ~~2022; and Xcel Energy’s cash flows for the three months ended March 31, 2023 and 2022.~~2023.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, ~~2023,~~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, ~~2022~~2023 balance sheet information has been derived from the audited ~~2022~~2023 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2022.~~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, ~~2022,~~2023, filed with the SEC on Feb. ~~23, 2023.~~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, ~~2022~~2023 appropriately represent, in all material respects, the current status of accounting policies and are ~~incorporated~~incorporated herein by reference.


2. Accounting Pronouncements

AsRecently 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 ~~March 31, 2023, there was no~~the new disclosure guidance to have a material impact ~~from~~to its consolidated financial statements.

Income Taxes — In December 2023, the ~~recent adoption~~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 ~~accounting pronouncements, nor expected~~disclosure guidance to have a material impact ~~from recently issued accounting pronouncements yet~~ to ~~be adopted, on Xcel Energy’s~~its consolidated financial statements.

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


3. Selected Balance Sheet Data

(Millions of Dollars)

March 31, 2023

Dec. 31, 2022

(Millions of Dollars)

March 31, 2024

Dec. 31, 2023

Accounts receivable, net

Accounts receivable

1,426

1,495

Accounts receivable

Less allowance for bad debts

(126)

(122)

Accounts receivable, net

1,300

1,373


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

(Millions of Dollars) March 31, 2023 Dec. 31, 2022
Inventories
Materials and supplies $ 340 $ 330
Fuel 169 201
Natural gas 71 272
Total inventories $ 580 $ 803


(Millions of Dollars)	(Millions of Dollars)	March 31, 2023		Dec. 31, 2022		(Millions of Dollars)	March 31, 2024	Dec. 31, 2023
Property, plant and equipment, net	Property, plant and equipment, net
Electric plant
Electric plant
Electric plant	Electric plant	$	50,227	$	49,639
Natural gas plant	Natural gas plant	8,612		8,514
Common and other property	Common and other property	3,001		2,970
Plant to be retired (a)	Plant to be retired (a)	2,180		2,217
Construction work in progress	Construction work in progress	2,224		2,124
Total property, plant and equipment	Total property, plant and equipment	66,244		65,464
Less accumulated depreciation	Less accumulated depreciation	(17,694)		(17,502)
Nuclear fuel	Nuclear fuel	3,266		3,183
Less accumulated amortization	Less accumulated amortization	(2,920)		(2,892)
Property, plant and equipment, net	Property, plant and equipment, net	$	48,896	$	48,253

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


4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Table of Contents

Commercial paper and term loan borrowings outstanding for Xcel Energy:


(Amounts in Millions, Except Interest Rates)	(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2023			Year Ended Dec. 31, 2022			(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2024		Year Ended Dec. 31, 2023
Borrowing limit	Borrowing limit	$	3,550		$	3,550
Amount outstanding at period end	Amount outstanding at period end	1,079			813
Average amount outstanding	Average amount outstanding	928			552
Maximum amount outstanding	Maximum amount outstanding	1,241			1,357
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	4.85		%	1.47		%	Weighted average interest rate, computed on a daily basis	5.53	%	5.12	%
Weighted average interest rate at period end	Weighted average interest rate at period end	5.23			4.66

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 ~~were $43~~was $44 million of letters of credit outstanding under the credit facilities at both March 31, ~~2023~~2024 and Dec. 31, ~~2022.~~2023. Amounts approximate their fair value and are subject to fees.

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

As of March 31, ~~2023,~~2024, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		(Millions of Dollars)	Credit Facility (a)	Drawn (b)	Available
Xcel Energy Inc.	Xcel Energy Inc.	$	1,500	$	510	$	990
PSCo	PSCo	700		385		315
NSP-Minnesota	NSP-Minnesota	700		135		565
SPS	SPS	500		80		420
NSP-Wisconsin	NSP-Wisconsin	150		12		138
Total	Total	$	3,550	$	1,122	$	2,428

(a)Expires in September 2027.

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

~~Table of Contents~~

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of March 31, ~~2023~~2024 and Dec. 31, ~~2022.~~2023.

Bilateral Credit Agreement

In April ~~2023,~~2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of March 31, ~~2023,~~2024, NSP-Minnesota had ~~$53~~$65 million of outstanding letters of credit under the $75 million bilateral credit agreement.

Long-Term Borrowings and Other Financing Instruments

~~On April 3, 2023, PSCo~~During the three months ended March 31, 2024, Xcel Energy Inc. and its utility subsidiaries issued ~~$850~~the following:

•Xcel Energy Inc. issued $800 million of ~~5.25% first mortgage bonds~~5.50% Senior Unsecured Notes due ~~April 1, 2053.~~March 15, 2034.

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

On April ~~21, 2023, NSP-Wisconsin priced a private placement of $125~~4, 2024, PSCo issued $450 million of ~~5.30% first mortgage bonds~~5.35% First Mortgage Bonds due ~~June~~May 15, ~~2053. The closing~~2034 and $750 million of ~~the sale of the bonds is subject to execution of a bond purchase agreement and customary closing conditions and is expected to occur in June 2023.~~5.75% First Mortgage Bonds due May 15, 2054.

ATM Equity Offering — In ~~November 2021,~~October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to ~~$800 million~~$2.5 billion of its common stock through an ATM program. In ~~2021, 5.33 million shares were~~2023, Xcel Energy Inc. issued ~~(approximately $350 million). In 2022, 4.30~~3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In the three months ended March 31, 2024, no shares were issued ~~(approximately $300 million).~~under the ATM program. As of March 31, ~~2023,~~2024, approximately ~~$150 million~~$2.3 billion remained available for sale under the ATM program.

~~Other~~ Equity through DRIP and Benefits Program — Xcel Energy ~~Inc.~~ issued ~~$15~~$17 million and ~~$10~~$15 million of equity through the DRIP and benefits programs during the three months ended March 31, ~~2023~~2024 and ~~2022,~~2023, respectively. The ~~program allows~~programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.


5. Revenues

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


			Three Months Ended March 31, 2023
		Three Months Ended March 31, 2024													Three Months Ended March 31, 2024
(Millions of Dollars)	(Millions of Dollars)		Electric		Natural Gas		All Other		Total		(Millions of Dollars)	Electric	Natural Gas	All Other		Total
Major revenue types	Major revenue types
Revenue from contracts with customers:
Revenue from contracts with customers:
Revenue from contracts with customers:
Residential	Residential		$	875	$	789	$	13	$	1,677
C&I	C&I		1,352		423		12		1,787
Other	Other		36		—		1		37
Total retail	Total retail		2,263		1,212		26		3,501
Wholesale	Wholesale		224		—		—		224
Transmission	Transmission		163		—		—		163
Other	Other		9		48		—		57
Total revenue from contracts with customers	Total revenue from contracts with customers		2,659		1,260		26		3,945
Alternative revenue and other	Alternative revenue and other		104		28		3		135
Total revenues	Total revenues		$	2,763	$	1,288	$	29	$	4,080

Table of Contents

Three Months Ended March 31, 2022
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 817 $ 663 $ 9 $ 1,489
C&I 1,235 356 2 1,593
Other 32 — 14 46
Total retail 2,084 1,019 25 3,128
Wholesale 259 — — 259
Transmission 152 — — 152
Other 23 45 — 68
Total revenue from contracts with customers 2,518 1,064 25 3,607
Alternative revenue and other 115 26 3 144
Total revenues $ 2,633 $ 1,090 $ 28 $ 3,751


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


6. Income Taxes

Reconciliation between the statutory rate and ETR:

Three Months Ended March 31

2023

2022

Three Months Ended March 31

2024

Federal statutory rate

21.0

State tax (net of federal tax effect)

4.8

4.9

Decreases:

State tax (net of federal tax effect)

(Decreases) increases:

Wind PTCs (a)

(33.1)

(34.4)

Plant regulatory differences (b)

(5.5)

(4.8)

Other tax credits, net operating loss & tax credits allowances

(1.6)

(1.5)

Plant regulatory differences (b)

Other tax credits, net operating loss & tax credit allowances

Other (net)

(0.1)

(0.4)

Effective income tax rate

(14.5)

(15.2)

Effective income tax rate

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

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


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.

~~Table of Contents~~

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

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

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

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

Three Months Ended March 31

(Shares in Millions)

2023

2022

Basic

551

545

Basic

Diluted (a)

551

545

Diluted (a)

(a)Diluted common shares outstanding included common stock equivalents of 0.2 million for the three months ended March 31, ~~2023~~2024 and ~~2022, respectively.~~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.

Table of Contents

Commodity ~~Derivatives~~derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.

The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.

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

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

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $1$1.3 billion and $1.2 billion as of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, respectively, and unrealized losses were ~~$61~~$34 million and ~~$90~~$29 million as of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, respectively.

~~Table of Contents~~

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


			March 31, 2023
						Fair Value
		March 31, 2024																				March 31, 2024
					Fair Value																			Fair Value
(Millions of Dollars)	(Millions of Dollars)		Cost			Level 1		Level 2		Level 3		NAV		Total		(Millions of Dollars)	Cost	Level 1	Level 2	Level 3	NAV		Total
Nuclear decommissioning fund (a)	Nuclear decommissioning fund (a)															Nuclear decommissioning fund (a)
Cash equivalents	Cash equivalents		$	44		$	44	$	—	$	—	$	—	$	44
Commingled funds	Commingled funds		743			—		—		—		1,076		1,076
Debt securities	Debt securities		751			—		707		7		—		714
Equity securities	Equity securities		507			1,172		2		—		—		1,174
Total	Total		$	2,045		$	1,216	$	709	$	7	$	1,076	$	3,008

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes ~~$228~~$247 million of equity method investments and ~~$137~~$151 million of rabbi trust assets and other miscellaneous investments.


			Dec. 31, 2022
						Fair Value
		Dec. 31, 2023																				Dec. 31, 2023
					Fair Value																			Fair Value
(Millions of Dollars)	(Millions of Dollars)		Cost			Level 1		Level 2		Level 3		NAV		Total		(Millions of Dollars)	Cost	Level 1	Level 2	Level 3	NAV		Total
Nuclear decommissioning fund (a)	Nuclear decommissioning fund (a)															Nuclear decommissioning fund (a)
Cash equivalents	Cash equivalents		$	29		$	29	$	—	$	—	$	—	$	29
Commingled funds	Commingled funds		803			—		—		—		1,178		1,178
Debt securities	Debt securities		738			—		669		6		—		675
Equity securities	Equity securities		406			999		1		—		—		1,000
Total	Total		$	1,976		$	1,028	$	670	$	6	$	1,178	$	2,882

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes ~~$219~~$244 million of equity investments in unconsolidated subsidiaries and ~~$133~~$144 million of rabbi trust assets and other miscellaneous investments.

For the three months ended March 31, ~~2023~~2024 and ~~2022,~~2023, there were ~~immaterial~~no Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of March 31, ~~2023:~~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

(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

220

254

239

714

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 ~~$82~~$92 million and ~~$80~~$88 million at March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~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.

Table of Contents

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

As of March 31, ~~2023,~~2024, accumulated other comprehensive loss related to interest rate derivatives included $2$1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of March 31, ~~2023,~~2024, Xcel Energy had no unsettled interest swaps ~~outstanding with a notional amount of $495 million.~~outstanding.

See Note 11 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.

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

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

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

The most significant derivative positions outstanding at March 31, ~~2023~~2024 and Dec. 31, ~~2022~~2023 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.

When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of March 31, ~~2023,~~2024, Xcel Energy had no commodity contracts designated as cash flow hedges.

~~Table of Contents~~

Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b)

March 31, 2023

Dec. 31, 2022

(Amounts in Millions) (a)(b)

March 31, 2024

Dec. 31, 2023

Megawatt hours of electricity

Million British thermal units of natural gas

117

131

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

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

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

Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.

As of March 31, ~~2023,~~2024, four of Xcel Energy’s ten most significant counterparties for these activities, comprising ~~$60~~$43 million, or ~~32%~~22%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

~~Three~~Five of the ten most significant counterparties, comprising ~~$54~~$68 million, or ~~28%~~34%, of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.

~~Three~~One of these significant counterparties, comprising ~~$77~~$54 million, or ~~40%~~27%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. ~~Six~~Eight of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.

As of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, there were $8$14 million and $4$12 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.

Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

As of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, there were approximately ~~$84~~$86 million and ~~$76~~$88 million of derivative liabilities with such underlying contract provisions, respectively.

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

Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, ~~2023~~2024 and Dec. 31, ~~2022.~~2023.

Table of Contents

Recurring Derivative Fair Value Measurements

Impact of derivative activity:


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory Assets and Liabilities
Three Months Ended March 31, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	29	$	—
Total	$	29	$	—
Other derivative instruments:
Electric commodity	$	—	$	(1)
Natural gas commodity	—		4
Total	$	—	$	3




















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











~~Three Months Ended March 31, 2022~~
~~Derivatives designated as cash flow hedges:~~
~~Interest rate~~	$	6	$	—
~~Total~~	$	6	$	—
~~Other derivative instruments:~~
~~Electric commodity~~	$	—	$	1
~~Natural gas commodity~~	—		4
~~Total~~	$	—	$	5

Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Assets and Liabilities
Three Months Ended March 31, 2023
Derivatives designated as cash flow hedges:
Interest rate $ 1 (a) $ — $ —
Total $ 1 $ — $ —
Other derivative instruments:
Commodity trading $ — $ — $ (1) (b)
Electric commodity — 82 (c) —
Natural gas commodity — 9 (d) (19) (d)(e)
Total $ — $ 91 $ (20)
Three Months Ended March 31, 2022
Derivatives designated as cash flow hedges:
Interest rate $ 2 (a) $ — $ —
Total $ 2 $ — $ —
Other derivative instruments:
Commodity trading $ — $ — $ 2 (b)
Electric commodity — (13) (c) —
Natural gas commodity — 3 (d) (17) (d)(e)
Total $ — $ (10) $ (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 March 31, 2024
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(8)	(b)
Electric commodity	—			12		(c)	—
Natural gas commodity	—			—			(14)		(d)(e)
Total	$	—		$	12		$	(22)











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

(a)Recorded to interest charges.

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

(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.

(d)~~Recorded~~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. ~~These losses~~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.

~~Table of Contents~~

Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, ~~2023~~2024 and ~~2022.~~2023.

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


			March 31, 2023														Dec. 31, 2022
			Fair Value						Fair Value Total			Netting (a)		Total			Fair Value												Fair Value Total				Netting (a)				Total
		March 31, 2024																																										March 31, 2024					Dec. 31, 2023
		Fair Value																																									Fair Value		Fair Value Total	Netting (a)	Total	Fair Value		Fair Value Total	Netting (a)	Total
(Millions of Dollars)	(Millions of Dollars)		Level 1		Level 2		Level 3				Fair Value Total				Netting (a)			Total				Level 1				Level 2						Level 3								Fair Value Total	Netting (a)	Total
Current derivative assets
Current derivative assets
Current derivative assets	Current derivative assets

Other derivative instruments:	Other derivative instruments:

Other derivative instruments:

Other derivative instruments:
Commodity trading
Commodity trading
Commodity trading	Commodity trading		$	11	$	152	$	21	$	184		$	(124)	$		60			$	32			$	259			$	33			$	324			$	(242)			$	82
Electric commodity	Electric commodity		—		—		34		34			—		34			—				—				177				177				(2)				175
Natural gas commodity	Natural gas commodity		—		—		—		—			—		—			—				19				—				19				—				19
Total current derivative assets	Total current derivative assets		$	11	$	152	$	55	$	218		$	(124)	94			$	32			$	278			$	210			$	520			$	(244)			276
PPAs (b)	PPAs (b)													3																							3
Current derivative instruments	Current derivative instruments													$	97																						$	279
Noncurrent derivative assets	Noncurrent derivative assets
Other derivative instruments:	Other derivative instruments:
Other derivative instruments:
Other derivative instruments:
Commodity trading	Commodity trading		$	24	$	62	$	78	$	164		$	(69)	$	95		$	34			$	71			$	74			$	179			$	(89)			$	90
Commodity trading
Commodity trading
Electric commodity
Total noncurrent derivative assets

Total noncurrent derivative assets			$	24	$	62	$	78	$	164		$	(69)	95			$	34			$	71			$	74			$	179			$	(89)			90
PPAs (b)														2																							3
Noncurrent derivative instruments														$	97																						$	93


			March 31, 2023																	Dec. 31, 2022
			Fair Value						Fair Value Total			Netting (a)				Total				Fair Value															Fair Value Total						Netting (a)						Total
		March 31, 2024																																																						March 31, 2024					Dec. 31, 2023
		Fair Value																																																					Fair Value		Fair Value Total	Netting (a)	Total	Fair Value		Fair Value Total	Netting (a)	Total
(Millions of Dollars)	(Millions of Dollars)		Level 1		Level 2		Level 3				Fair Value Total						Netting (a)				Total					Level 1					Level 2							Level 3												Fair Value Total			Netting (a)	Total
Current derivative liabilities	Current derivative liabilities
Current derivative liabilities
Current derivative liabilities
Derivatives designated as cash flow hedges:
Derivatives designated as cash flow hedges:
Derivatives designated as cash flow hedges:	Derivatives designated as cash flow hedges:
Interest rate	Interest rate		$	—	$	6	$	—	$	6				$	—			$	6				$	—				$	1				$	—					$	1					$	—					$	1
Interest rate
Interest rate
Other derivative instruments:	Other derivative instruments:
Commodity trading
Commodity trading
Commodity trading	Commodity trading		$	9	$	180	$	4	$	193		$	(153)			$		40				$	29				$	297				$	6				$	332					$	(287)					$	45
Electric commodity	Electric commodity		—		—		1		1			(1)				—				—					—					2					2						(2)						—
Natural gas commodity	Natural gas commodity		—		—		—		—			—				—				—					13					—					13						—						13
Total current derivative liabilities	Total current derivative liabilities		$	9	$	186	$	5	$	200		$	(154)			46				$	29				$	311				$	8				$	348					$	(289)					59
PPAs (b)	PPAs (b)															16																															17
Current derivative instruments	Current derivative instruments															$	62																														$	76
Noncurrent derivative liabilities	Noncurrent derivative liabilities
Other derivative instruments:	Other derivative instruments:
Other derivative instruments:
Other derivative instruments:
Commodity trading
Commodity trading
Commodity trading	Commodity trading		$	30	$	77	$	50	$	157		$	(69)			$	88			$	43				$	97				$	41				$	181					$	(98)					$	83
Total noncurrent derivative liabilities	Total noncurrent derivative liabilities		$	30	$	77	$	50	$	157		$	(69)			88				$	43				$	97				$	41				$	181					$	(98)					83
PPAs (b)	PPAs (b)															28																															30
Noncurrent derivative instruments	Noncurrent derivative instruments															$	116																														$	113

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, derivative assets and liabilities include no obligations to return cash collateral. At March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, derivative assets and liabilities include rights to reclaim cash collateral of ~~$29~~$8 million and ~~$53~~$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.

1516

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Changes in Level 3 commodity derivatives:


		Three Months Ended March 31
		Three Months Ended March 31

		Three Months Ended March 31

		Three Months Ended March 31
(Millions of Dollars)	(Millions of Dollars)	2023		2022		(Millions of Dollars)	2024	2023
Balance at Jan. 1	Balance at Jan. 1	$	235	$	19
Purchases (a)	Purchases (a)	6		5
Settlements (a)	Settlements (a)	(29)		(50)
Net transactions recorded during the period:	Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)		(13)		42
Net (losses) gains recognized as regulatory assets and liabilities (a)		(121)		24
Losses recognized in earnings (b)
Losses recognized in earnings (b)
Losses recognized in earnings (b)
Net gains (losses) recognized as regulatory assets and liabilities (a)
Balance at March 31	Balance at March 31	$	78	$	40

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

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

Fair Value of Long-Term Debt

As of March 31, ~~2023,~~2024, other financial instruments for which the carrying amount did not equal fair value:

March 31, 2023

Dec. 31, 2022

March 31, 2024

Dec. 31, 2023

(Millions of Dollars)

Carrying Amount

Fair Value

Carrying Amount

Fair Value

(Millions of Dollars)

Carrying Amount

Fair Value

Carrying Amount

Fair Value

Long-term debt, including current portion

23,719

21,167

23,964

20,897

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~2023, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.


9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


			Three Months Ended March 31
			2023		2022		2023		2022
		Three Months Ended March 31														Three Months Ended March 31
		2024											2024		2023	2024	2023
(Millions of Dollars)	(Millions of Dollars)		Pension Benefits				Postretirement Health Care Benefits				(Millions of Dollars)	Pension Benefits		Postretirement Health Care Benefits
Service cost	Service cost		$	18	$	24	$	—	$	—
Interest cost (a)	Interest cost (a)		40		27		5		4
Expected return on plan assets (a)	Expected return on plan assets (a)		(52)		(52)		(4)		(4)
Amortization of prior service credit (a)			—		—		—		(2)

Amortization of net loss (a)	Amortization of net loss (a)		5		19		1		1
Settlement charge (b)			—		(1)		—		—
Net periodic benefit cost (credit)			11		17		2		(1)
Amortization of net loss (a)
Amortization of net loss (a)

Net periodic benefit cost
Net periodic benefit cost
Net periodic benefit cost
Effects of regulation	Effects of regulation		5		5		—		1
Net benefit cost recognized for financial reporting	Net benefit cost recognized for financial reporting		$	16	$	22	$	2	$	—

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

~~(b)In the first quarter of 2022, Xcel Energy recognized $1 million in settlement charge true-ups related to the fourth quarter of 2021.~~

In January ~~2023,~~2024, contributions totaling ~~$50~~$100 million were made across Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during ~~2023.~~2024.


10. Commitments and Contingencies

Legal

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

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

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

One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected ~~later this year.~~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 ~~January 2022, the Court granted PSCo’s motion to dismiss CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In~~ April 2022, CORE filed a supplement to include ~~the January 2022 outage and~~ damages related to ~~this event.~~a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

In ~~February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million. Also in February~~October 2023, the ~~court granted PSCo’s motion precluding~~jury ruled that CORE ~~from seeking damages related to its withdrawal~~may not withdraw as ~~part~~a joint owner of the ~~lawsuit.~~facility but awarded CORE lost power damages of $26 million. PSCo ~~continues~~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 ~~believe CORE's claims are without merit and disputes CORE’s right to withdraw.~~the Colorado Court of Appeals.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Rate Matters and Other

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

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

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

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

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

~~MISO ROE Complaints~~ ~~— In November 2013~~

Environmental

New and ~~February 2015, customer groups filed two ROE complaints against MISO TOs,~~changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which ~~includes NSP-Minnesota~~are normally recovered through the regulated rate process.

Site Remediation

Various federal and ~~NSP-Wisconsin. The first complaint requested~~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 ~~reduction in base ROE transmission formula rates from 12.38%~~portion of the cost to ~~9.15% for the time period~~remediate sites where past activities of ~~Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership).The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.~~

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

~~The MISO TOs and various~~their predecessors or other parties have ~~filed petitions~~caused environmental contamination.

Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for ~~review~~which one or more of ~~the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled~~Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that FERC had not adequately supported its conclusions, vacated FERC’s related orders, and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial.

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

In 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In 2021, the D.C. Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates.

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

~~Environmental~~site.

MGP, Landfill and Disposal Sites

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

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Xcel Energy has recognized ~~its best estimate~~approximately $20 million of costs/liabilities from final resolution of these ~~issues,~~issues; however, the outcome and timing are unknown. In addition, there may be regulatory recovery, insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid ~~waste. Under~~waste, including the CCR Rule. As a specific requirement of the CCR Rule, utilities ~~are required to~~must complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.

AsIf certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of ~~March 31, 2023,~~Corrective Measures.

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

For required coal ash ~~units in operation.~~

disposal, PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $45 million. An estimated liability has been recorded, ~~and amounts are expected to be fully recoverable through regulatory mechanisms.~~

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~~Investigation and feasibility studies for additional corrective action~~deferred accounting related to ~~offsite groundwater are ongoing (at three Colorado sites). While the results are uncertain, additional~~these costs ~~are estimated to be at least $30 million. A liability~~ has been ~~recorded for~~approved by the ~~portion of these actions that are estimable/probable,~~CPUC and amounts are expected to be fully recoverable through regulatory mechanisms.

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

Estimated capital expenditures of approximately ~~$45~~$50 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.

~~Monticello Tritium~~Environmental Requirements — Air

Clean Air Act NOx Allowance Allocations — ~~— Monticello regularly monitors onsite tritium levels (a weak radioactive isotope~~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 ~~is a byproduct of plant operations) from releases in groundwater monitoring wells onsite. In late 2022,~~will impact Xcel Energy ~~detected~~fossil fuel-fired electric generating facilities. Subject facilities will have to secure additional allowances, install NOx controls and/or develop a ~~release~~strategy of ~~tritium to groundwater~~operations that utilizes the existing allowance allocations. Guidelines are also established for allowance banking and ~~reported~~emission limit backstops.

While the ~~event to the NRC and the State of Minnesota. Xcel Energy has completed repairs, replaced the source~~financial impacts of the ~~release~~final rule are uncertain and ~~is extracting the impacted groundwater.~~dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs ~~to extract and contain the impacted groundwater from this release to~~could be ~~immaterial. The water is fully contained on-site and has not been detected in any drinking water. The release does not represent a risk to human health or the environment.~~significant, but would be recoverable through regulatory mechanisms.

~~Environmental Requirements~~ — ~~Air~~

~~Regional Haze Rules~~ —

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

In ~~2016,~~February 2024, the EPA ~~adopted a final rule establishing a federal~~proposed to partially disapprove New Mexico’s state implementation plan ~~for reasonable further progress under~~and bring New Mexico into the ~~regional haze program for the state of Texas. The rule imposes SO~~2 emission limitations which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.

~~In 2017, the EPA adopted a final BART rule for Texas. Under that rule, Harrington Units 1, 2, and 3 and Tolk Units 1 and 2 participate in intrastate SO~~2 ~~budget and trading program. The rule also implemented participation in a~~ federal ozone season NOx budget and trading program, named the Cross State Air Pollution Rule. The EPA is reconsidering this rule and a proposal for reconsideration is anticipated in the second quarter of 2023.Good Neighbor Plan. Xcel Energy continues to evaluate impacts to generation units at SPS.

Leases

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

Components of lease expense:


			Three Months Ended March 31
		Three Months Ended March 31								Three Months Ended March 31
(Millions of Dollars)	(Millions of Dollars)		2023		2022		(Millions of Dollars)	2024	2023
Operating leases	Operating leases
PPA capacity payments
PPA capacity payments
PPA capacity payments	PPA capacity payments		$	60	$	63
Other operating leases (a)	Other operating leases (a)		12		13
Total operating lease expense (b)	Total operating lease expense (b)		$	72	$	76
Finance leases	Finance leases
Amortization of ROU assets	Amortization of ROU assets		$	1	$	1
Amortization of ROU assets
Amortization of ROU assets
Interest expense on lease liability	Interest expense on lease liability		4		4
Total finance lease expense	Total finance lease expense		$	5	$	5

(a)Includes short-term lease expense of $1 million and $2 million for 2024 and ~~$1 million for~~ 2023, ~~and 2022,~~ respectively.

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

Commitments under operating and finance leases as of March 31, ~~2023:~~2024:


(Millions of Dollars)	(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)		(Millions of Dollars)	PPA Operating Leases	Other Operating Leases	Total Operating Leases	Finance Leases (a)
Total minimum obligation	Total minimum obligation	$	1,223	$	257	$	1,480	$	225
Interest component of obligation	Interest component of obligation	(160)		(76)		(236)		(160)
Present value of minimum obligation	Present value of minimum obligation	$	1,063	181		1,244		65
Less current portion	Less current portion					(224)		(2)
Noncurrent operating and finance lease liabilities	Noncurrent operating and finance lease liabilities					$	1,020	$	63

(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. ~~These specific PPAs create a variable interest in~~Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the ~~IPP.~~operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

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

Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because itXcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had ~~approxi~~ma~~tely 4,053 MW and 3,961~~approximately 3,751 MW of capacity under long-term PPAs atas of both March 31, ~~2023~~2024 and Dec. 31, ~~2022, respectively,~~2023, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2041.

Other

Guarantees and Bond Indemnifications — Xcel Energy ~~provides~~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 ~~agreements.~~specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.

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As of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~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 ~~$62~~$75 million at both March 31, ~~2023~~2024 and Dec. 31, ~~2022~~.2023, respectively.

Other Indemnification Agreements — Xcel Energy ~~provides~~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’s~~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.~~estimated as the dollar amounts are often not explicitly stated.


11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of ~~tax :~~tax:


			Three Months Ended March 31, 2023						Three Months Ended March 31, 2022
		Three Months Ended March 31, 2024																	Three Months Ended March 31, 2024			Three Months Ended March 31, 2023
(Millions of Dollars)	(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		(Millions of Dollars)	Gains and Losses on Cash Flow Hedges	Defined Benefit Pension and Postretirement Items	Total		Gains and Losses on Cash Flow Hedges	Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	Accumulated other comprehensive loss at Jan. 1		$	(54)	$	(39)	$	(93)	$	(75)	$	(48)	$	(123)
Other comprehensive (loss) gain before reclassifications			(5)		—		(5)		5		—		5
Other comprehensive gain (loss) before reclassifications
Losses reclassified from net accumulated other comprehensive loss:	Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)	Interest rate derivatives (a)		1		—		1		1		—		1
Amortization of net actuarial loss (b)			—		—		—		—		1		1
Net current period other comprehensive (loss) income			(4)		—		(4)		6		1		7
Interest rate derivatives (a)
Interest rate derivatives (a)

Net current period other comprehensive income (loss)
Net current period other comprehensive income (loss)
Net current period other comprehensive income (loss)
Accumulated other comprehensive loss at March 31	Accumulated other comprehensive loss at March 31		$	(58)	$	(39)	$	(97)	$	(69)	$	(47)	$	(116)

(a)Included in interest charges.

~~(b)Included in the computation of net periodic pension and postretirement benefit costs.~~

12. Segment Information

Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo.

These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Xcel Energy has the following reportable segments:

•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair, ~~services,~~ non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

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Xcel Energy had equity method investments of ~~$228~~$247 million and ~~$219~~$244 million as of March 31, ~~2023~~2024 and Dec. 31, ~~2022,~~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.

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Xcel Energy’s segment information:


			Three Months Ended March 31
		Three Months Ended March 31								Three Months Ended March 31
(Millions of Dollars)	(Millions of Dollars)		2023		2022		(Millions of Dollars)	2024	2023
Regulated Electric	Regulated Electric

Operating revenues
Operating revenues
Operating revenues
Intersegment revenue
Total revenues	Total revenues		$	2,763	$	2,633
Net income	Net income		296		278
Regulated Natural Gas	Regulated Natural Gas
Operating revenues
Operating revenues
Operating revenues	Operating revenues		$	1,288	$	1,090
Intersegment revenue	Intersegment revenue		1		—
Total revenues	Total revenues		$	1,289	$	1,090
Net income	Net income		159		130
All Other	All Other
Total revenues	Total revenues		$	29	$	28
Total revenues
Total revenues
Net loss	Net loss		(37)		(28)
Consolidated Total	Consolidated Total
Total revenues
Total revenues
Total revenues	Total revenues		$	4,081	$	3,751
Reconciling eliminations	Reconciling eliminations		(1)		—
Total operating revenues	Total operating revenues		$	4,080	$	3,751
Net income	Net income		418		380

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

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

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

Non-GAAP Financial Measures

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

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

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

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

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

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. For the three months ended March 31, ~~2023~~2024 and ~~2022,~~2023, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

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

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Summarized diluted EPS for Xcel Energy:

Three Months Ended March 31
Diluted Earnings (Loss) Per Share 2023 2022
PSCo $ 0.39 $ 0.32
NSP-Minnesota 0.25 0.23
SPS 0.10 0.10
NSP-Wisconsin 0.08 0.09
Earnings from equity method investments — WYCO 0.01 0.01
Regulated utility (a)
0.83 0.75
Xcel Energy Inc. and Other (0.07) (0.05)
Total (a)
$ 0.76 $ 0.70

~~(a)~~ ~~Amounts may not add due to rounding.~~


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

Summary of Earnings

Xcel Energy — Xcel Energy’s first quarter GAAP and ongoing diluted earnings were $0.88 per share, compared with $0.76 per share in ~~2023 compared with $0.70~~the same period in 2023. The increase in earnings per share ~~in 2022. The increase~~ was primarily driven by increased recovery of ~~electric~~infrastructure investments, higher AFUDC and ~~natural gas infrastructure investment,~~lower O&M expenses, partially offset by ~~higher depreciation, O&M expenses~~increased interest charges and ~~interest charges.~~depreciation. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

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

~~PSCo~~NSP-Minnesota — ~~Earnings~~GAAP and ongoing earnings increased ~~$0.07~~$0.13 per share for the first quarter of ~~2023.~~2024. The ~~higher earnings primarily reflect the timing of~~change was driven by increased recovery of electric and natural gas infrastructure ~~investment~~investments and ~~the impact of colder than normal weather,~~lower O&M expenses, partially offset by ~~increased depreciation, O&M expenses and~~higher interest charges. Incremental investment recovery was implemented for electric operations in April 2022 and natural gas operations in November 2022, resulting in higher revenues in the first quarter of 2023 compared to 2022. The year-over-year impact of these higher revenues is not expected to continue throughout the rest of the year. Earnings are not a result of higher natural gas prices as PSCo does not profit on fuel or power costs purchased for its customers.

~~NSP-Minnesota~~ — ~~Earnings increased $0.02 per share for the first quarter of 2023. The increase is primarily due to recovery of electric infrastructure investment, partially offset by increased O&M~~ expenses and depreciation.

SPS — ~~Earnings~~GAAP and ongoing earnings were flat for the first quarter of ~~2023. Recovery of electric infrastructure investment~~2024 primarily due to regulatory rate outcomes and ~~strong sales growth were~~lower O&M expenses, offset by ~~higher~~increased depreciation and ~~O&M~~amortization expenses.

NSP-Wisconsin — ~~Earnings decreased $0.01 per share~~GAAP and ongoing earnings were flat for the first quarter of ~~2023. Recovery of electric and natural gas infrastructure investment~~2024 as lower O&M expenses were ~~more than~~ offset by ~~impacts of warmer winter weather, higher depreciation and O&M expenses.~~increased depreciation.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments. ~~Earnings decreased $0.02 per share for the first quarter,~~The decline in earnings is largely ~~attributable~~due to ~~higher~~increased interest ~~charges.~~rates.

Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in ~~2023~~2024 EPS compared to ~~2022:~~2023:

Diluted Earnings (Loss) Per Share

Three Months Ended March 31

~~GAAP and ongoing diluted EPS — 2022~~

~~0.70~~

~~Components of change - 2023 vs. 2022~~

~~Higher electric revenues, net of electric fuel and purchased power~~

~~0.15~~

~~Higher natural gas revenues, net of cost of natural gas sold and transported~~

~~0.09~~

~~Lower effective tax rate (ETR)~~ ~~(a)~~

~~0.02~~

~~Higher depreciation and amortization~~

~~(0.08)~~

~~Higher O&M expenses~~

~~(0.06)~~

~~Higher interest charges~~

~~(0.05)~~

~~Higher taxes (other than income taxes)~~

~~(0.02)~~

~~Other, net~~

~~0.01~~

GAAP and ongoing diluted EPS — 2023

0.76

Components of change - 2024 vs. 2023

Lower cost of natural gas sold and transported (a)

0.49

Lower electric fuel and purchased power (a)

0.23

Lower O&M expenses

0.06

Higher AFUDC

0.04

Lower natural gas revenues

(0.47)

Lower electric revenues

(0.11)

Higher depreciation and amortization

(0.05)

Higher interest charges

(0.05)

Other, net

(0.02)

GAAP and ongoing diluted EPS — 2024

0.88

(a)~~Includes PTCs~~Cost of natural gas sold and ~~plant~~transported and electric fuel and purchased power are generally recovered through regulatory ~~amounts, which are primarily~~recovery mechanisms and offset ~~as a reduction to electric revenues.~~in revenue.

Statement of Income Analysis

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

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

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

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

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

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

Percentage increase (decrease) in normal and actual HDD:

Three Months Ended March 31
2023 vs. Normal 2022 vs. Normal 2023 vs. 2022
HDD 1.4 % 9.7 % (7.3) %


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

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


			Three Months Ended March 31
				2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
		Three Months Ended March 31
		Three Months Ended March 31
		Three Months Ended March 31
		2024 vs. Normal
		2024 vs. Normal
		2024 vs. Normal
Retail electric	Retail electric			$	0.002	$	0.020	$	(0.018)
Decoupling				(0.006)		(0.010)		0.004
Retail electric
Retail electric
Decoupling and sales true-up
Decoupling and sales true-up
Decoupling and sales true-up
Electric total
Electric total
Electric total	Electric total			$	(0.004)	$	0.010	$	(0.014)
Firm natural gas	Firm natural gas			0.029		0.016		0.013
Firm natural gas
Firm natural gas
Decoupling
Decoupling
Decoupling
Gas total
Gas total
Gas total
Total	Total			$	0.025	$	0.026	$	(0.001)
Total
Total

Sales — Sales growth (decline) for actual and weather-normalized sales in ~~2023~~2024 compared to ~~2022:~~2023:

Three Months Ended March 31
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential 0.6 % (4.2) % (2.7) % (6.4) % (2.4) %
Electric C&I (1.2) (1.8) 7.3 — 1.0
Total retail electric sales (0.6) (2.6) 5.3 (2.0) —
Firm natural gas sales 5.8 (10.1) N/A (14.3) (1.1)

~~Table of Contents~~


			Three Months Ended March 31
			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
		Three Months Ended March 31																			Three Months Ended March 31
		PSCo													PSCo		NSP-Minnesota		SPS			NSP-Wisconsin		Xcel Energy
Actual
Electric residential
Electric residential
Electric residential	Electric residential		(0.9)	%	(1.2)	%	3.1	%	(0.9)	%	(0.4)	%	(2.2)	%	(5.7)	%	(1.7)	%	(7.3)	%		(4.0)	%
Electric C&I	Electric C&I		(1.4)		(1.3)		7.2		0.6		1.1
Total retail electric sales	Total retail electric sales		(1.3)		(1.3)		6.3		0.2		0.6
Firm natural gas sales	Firm natural gas sales		(0.1)		(1.4)		N/A		(2.1)		(0.7)



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


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

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

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

•NSP-Minnesota — Residential sales decreased due to a 3.5% decrease in use per customer, partially offset by a ~~1.3%~~1.5% increase in customers. ~~The~~ C&I ~~sales decline was attributable to decreased use per customer, primarily due to a two-month outage at a large manufacturing sector customer.~~

•~~NSP-Minnesota — Residential~~ sales declined due to decreased use per customer, ~~partially offset by a 1.0% increase in customers. The C&I sales decline was attributable to lower use per customer, primarily driven by declines~~largely in the ~~educational, transportation and warehousing and retail trade sectors.~~manufacturing sector.

•SPS — Residential sales ~~growth was primarily attributable to increased~~declined as a result of a 4.6% decrease in use per customer, ~~in addition to a 0.8% increase in customers.~~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 ~~decreased~~a 4.9% decrease in use per customer, ~~primarily~~partially offset by ~~a 0.7%~~0.8% increase in customers. C&I sales ~~growth~~decline was ~~primarily~~ associated with decreased use per customer, ~~growth,~~ experienced ~~primarily~~largely in the ~~transportation and~~ professional services and manufacturing sectors.

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

•~~Natural~~Increase in natural gas sales ~~reflect a lower use per~~was driven by continued strength in PSCo residential ~~customer in all jurisdictions, partially offset by an increase in~~and C&I use per ~~customer in PSCo. In addition,~~customer. Additionally, overall residential and C&I customer growth was ~~1.2%~~1.1% and ~~0.7%~~0.6%, respectively.

Electric ~~Margin~~Revenues

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


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

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


Other (net)	(8)

Total decrease	$	(78)

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

Natural Gas Revenues

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

Table of Contents


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


Other (net)	6
Total decrease	$	(347)

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

Electric ~~revenues and~~ fuel and purchased power expenses ~~are impacted by fluctuations in~~decreased $169 million for the ~~price~~first quarter of ~~natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact~~2024. The decrease is primarily due to lower commodity prices and timing of fuel ~~recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.~~

~~Electric revenues, fuel and purchased power and margin:~~

Three Months Ended March 31
(Millions of Dollars) 2023 2022
Electric revenues $ 2,763 $ 2,633
Electric fuel and purchased power (1,117) (1,094)
Electric margin $ 1,646 $ 1,539

~~(Millions of Dollars)~~

~~Three Months Ended March 31, 2023 vs. 2022~~

~~Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, South Dakota and Wisconsin)~~

~~Sales and demand~~ ~~(a)~~

~~Wholesale transmission (net)~~

~~Non-fuel riders~~

~~Conservation and demand side management (offset in expense)~~

~~(17)~~

~~PTCs flowed back to customers (offset by a lower ETR)~~

~~(12)~~

~~Estimated impact of weather, net of decoupling~~

~~(10)~~

~~Other (net)~~

~~Total increase~~

~~107~~

recovery.

~~(a)Sales excludes weather impact, net~~Cost of ~~decoupling in Colorado and proposed decoupling in Minnesota.~~

Natural Gas ~~Margin~~

~~Natural gas margin is presented as natural gas revenues less the cost of natural gas sold~~Sold and ~~transported.~~ Transported —Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating ~~revenues.~~

~~Natural gas expense varies with changing sales~~revenues and ~~the cost of natural gas. However, fluctuations in the cost of natural gas generally~~ have minimal earnings ~~impact due to cost recovery mechanisms.~~impact.

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

Three Months Ended March 31
(Millions of Dollars) 2023 2022
Natural gas revenues $ 1,288 $ 1,090
Cost of natural gas sold and transported (844) (710)
Natural gas margin $ 444 $ 380


~~(Millions of Dollars)~~	~~Three Months Ended March 31, 2023 vs. 2022~~
~~Regulatory rate outcomes (Colorado and Wisconsin)~~	$	47
~~Estimated impact of weather~~	9

~~Infrastructure and integrity riders~~	4



~~Other (net)~~	4
~~Total increase~~	$	64

decreased volumes.

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses ~~increased $48~~decreased $45 million for the first quarter. ~~Increase~~The decrease was primarily due to ~~timing of recovery mechanisms, generation outages~~decreased labor and ~~emergent work; higher~~benefit costs, gain on land sale, and lower bad debt ~~expenses; the impact of inflationary pressures, including labor increases, and investments in electric vehicle programs and other customer products.~~expenses.

Depreciation and Amortization — Depreciation and amortization increased ~~$62~~$34 million for the first quarter ~~primarily driven by~~as a result of system expansion, ~~and~~offset by depreciation life extensions implemented in the ~~implementation of new depreciation rates in Colorado and Minnesota.~~Minnesota Electric Rate Case.

Interest Charges — Interest charges increased ~~$39~~$38 million for the first quarter, largely due to ~~higher interest rates and~~ increased long-term debt levels ~~to fund capital investments.~~and higher interest rates.

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


Public Utility Regulation and Other

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

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

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

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2022~~2023 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings

~~2022~~2024 Minnesota ~~Electric~~Natural Gas Rate Case — — In ~~October 2021,~~November 2023, NSP-Minnesota filed a ~~three-year electric rate case~~request with the ~~MPUC.~~MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The ~~rate case~~request is based on a ~~requested~~ ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test ~~years.~~

year with rate base of approximately $1.27 billion. In December ~~2021,~~2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of ~~$247~~approximately $51 million ~~effective~~(implemented on Jan. 1, ~~2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.~~2024).

On ~~March 31, 2023,~~April 19, 2024, four parties filed direct testimony. The DOC, OAG, and CUB were the ~~ALJ’s report was issued. NSP-Minnesota estimates that the ALJ recommendation would result in~~only parties to quantify recommended financial adjustments. The OAG and CUB provided limited comments, recommending a ~~rate increase~~reduction of approximately ~~$386~~$1 million ~~over three years from 2022-2024, based on~~of O&M expenses each. The CUB additionally recommended a ROE of 9.87% and an equity ratio of 52.5%. In addition, it also reflects rate reductions associated with certain wind and nuclear generation life extensions and MISO capacity revenues and related tracker, as proposed in NSP-Minnesota’s revised rate request. A MPUC order is expected by June 30, 2023.reduction to ROE.

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

(Millions of Dollars) 2022 2023 2024
NSP-Minnesota’s revised revenue request $ 234 $ 328 $ 498
ALJ recommended adjustments:
PTC forecast (28) (2) (1)
Impact of ROE change (27) (29) (30)
O&M expenses (15) (17) (18)
Property tax — (11) (23)
Sherco 3 and A.S. King remaining life — — (35)
Other, net 3 (9) (5)
Total adjustments (67) (68) (112)
Total proposed revenue change $ 167 $ 260 $ 386


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

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


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

Procedural schedule:

~~2022 Minnesota~~•Mediation: May 17, 2024 (day subject to availability)

•Rebuttal testimony: May 24, 2024

•Evidentiary hearings: July 10-12, 2024

•ALJ report: October 28, 2024

•MPUC Order Due: March 14, 2025

2024 North Dakota Natural Gas Rate Case —In ~~November 2021,~~ December 2023, NSP-Minnesota filed a request with the ~~MPUC~~ ~~for~~NDPSC seeking an ~~annual~~increase in natural gas ~~rate increase~~rates of ~~$36~~$8.5 million ~~or 6.6%. The filing is based on~~(9.4%), a ~~2022 forecast~~2024 test year, ~~and includes a requested~~ ROE of ~~10.5%~~10.20%, an equity ratio of 52.5% and a rate base of ~~$934~~$168 million. In ~~December 2021,~~February 2024, the ~~MPUC~~NDPSC approved an interim ~~rate increase~~rates of ~~$25~~$8 million, ~~subject to refund,~~ effective ~~Jan.~~March 1, ~~2022.~~2024.

~~In March 2023, the MPUC approved a settlement between NSP-Minnesota and various parties, which includes the following key terms:~~

•~~Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.~~

•~~Revenue decoupling mechanism.~~

•~~Symmetrical property tax true-up.~~

•~~ROE of 9.57%.~~

•~~Equity ratio of 52.5%.~~

~~2022 South Dakota Electric Rate Case~~ —In June 2022, NSP-Minnesota filed a South Dakota electric rate case (first since 2014) seeking a revenue increase of approximately $44 million. The filing was based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a requested ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. A commission decision is expected later this year.

~~Wind Repowering~~ — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval.

~~In March 2023, the MPUC approved the revised projects.~~

~~2022 Upper Midwest RFP~~ — In August 2022, NSP-Minnesota launched a RFP for 900 MW of solar or solar-plus-storage hybrid resources to come online by the end of 2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.

~~NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of selected projects in the second quarter of 2023.~~

~~2022 Minnesota Electric Vehicle Proposal~~ — In August 2022, NSP-Minnesota filed a request with the MPUC for approval of approximately $320 million of capital investments (2022 through 2026) to support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.

In February 2023, other parties to the contested proceeding filed their direct testimony ranging in levels of support/opposition to the proposals. In March 2023, the ALJ granted NSP-Minnesota’s request for a 60-day stay in the case so that the parties could pursue potential settlement. An evidentiary hearing has not been scheduled but is expected in June 2023. A MPUC decision is expected in late 2023.

2325

Table of Contents

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

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2022~~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, ~~2022,~~2023, appropriately represent, in all material respects, the current status of nuclear power ~~operations, and are incorporated by reference.~~operations.

~~NSP-Wisconsin~~

~~Upcoming Regulatory Proceedings~~NSP System

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

•~~On April 28,~~In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of 800 MW of firm dispatchable resources. In January 2024, NSP-Minnesota and other companies submitted proposed resources and filed for project approval with the MPUC. NSP-Minnesota expects a decision by the second quarter of 2025.

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

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

2024 Upper Midwest Resource Plan — In February 2024, NSP filed its Upper Midwest Resource Plan with the ~~PSCW seeking an electric increase~~MPUC which included the following key items:

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

•Extends the operation of ~~$40 million (an overall rate increase~~Prairie Island and Monticello through the early 2050s.

•Adds 3,600 MWs of ~~4.8%)~~new wind and ~~a natural gas increase~~solar resources by 2030.

•Adds 600 MWs of ~~$9 million (an overall rate increase~~battery energy storage by 2030.

•Adds more than 2,200 MWs of ~~5.3%). The rate request is based on a 2024 forward-looking test year with a requested ROE of 10.25% and a 52.5% equity ratio. A final decision~~dispatchable resources by 2030.

These proposed resources are in addition to projects already approved by the ~~PSCW is expected late fourth quarter 2023.~~MPUC. NSP-Minnesota anticipates a MPUC decision in 2025.

PSCo

Pending and Recently Concluded Regulatory Proceedings

Colorado ~~Electric~~Natural Gas Rate Case — In ~~November 2022,~~January 2024, PSCo filed a request with the CPUC seeking an ~~electric rate case seeking a net~~ increase to retail natural gas rates of ~~$262~~$171 million, or ~~8.2%. The total request reflects a $312 million~~an approximately 9.5% increase ~~which includes $50 million of authorized costs currently recovered through various rider mechanisms.~~in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of ~~55.7%~~55% and a ~~2023 forecast test year with a 2023 year-end~~$4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023. PSCo has requested a proposed effective date of ~~$11.3 billion. PSCo requested rates effective in September 2023.~~Nov. 1, 2024.

~~Next steps in~~PSCo has proposed to defer collection of the ~~procedural schedule are expected~~increased rates until Feb. 15, 2025 (following the expiration of the rider to ~~be as follows:~~recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date.

Procedural schedule:

•~~Answer testimony May 3, 2023.~~Intervenor testimony: July 11, 2024

•Rebuttal testimony: ~~May 31, 2023.~~Aug. 15, 2024

•Settlement deadline: ~~June 14, 2023.~~Aug. 27, 2024

•~~Hearing: July 6-21, 2023.~~Evidentiary hearing: Sept. 4-12, 2024

•Statement of position: ~~Aug. 10, 2023.~~Sept. 26, 2024

~~A CPUC decision is expected in the third quarter of 2023.~~

Colorado Resource Plan — In ~~August 2022,~~December 2023, the CPUC approved ~~an updated settlement,~~a portfolio of 5,835 MW, which ~~will result~~includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs. PSCo expects to invest approximately $4.8 billion in generation resources under the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recoveryportfolio for the ~~retiring coal units to a separate docket, which will consider accelerated depreciation, creation~~benefit of ~~regulatory assets~~its customers and ~~securitization. In April 2023, PSCo filed a coal cost recovery settlement with~~achieving the CPUC that includes regulatory asset recovery of the remaining plant balances at retirement and a potential bundled securitization of the remaining coal plant book values including Comanche Unit 3 in 2031.state’s clean energy goals.

In December ~~2022,~~2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in related proceedings throughout 2024.

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

Transportation Electrification Plan — In April 2024, the CPUC approved PSCo’s TEP with ~~bids due in March 2023. After reviewing~~modification, including a three-year budget of $264 million and continued cost recovery through the ~~bids received,~~ TEP rider. The CPUC approved PSCo’s proposal to offer rebates for residential chargers and wiring to be paired with residential managed charging programs and vehicle rebates for Income-Qualified customers, as well as its proposal to offer rebates for commercial public chargers and electric vehicle supply infrastructure. Additionally, the CPUC approved PSCo’s proposed budget to support innovation projects including electric school buses, Vehicle-to-Everything demonstrations, and stakeholder-driven projects with a focus on disproportionately impacted communities. The Commission also approved a WACC return on rebates with a 3-year amortization.

Wildfire Mitigation Plan — PSCo will file a ~~report with the CPUC with recommended resource acquisitions~~Wildfire Mitigation Plan and ~~a CPUC decision on the resources to be acquired is expected in November 2023.~~

~~Decoupling Filing~~— PSCo has a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.

~~In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of the 2020 decoupling refunds.~~

In April 2022, PSCo made its annual filing on this matter. In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and the UCA. In the first quarter of 2023, PSCo filed a petition for CPUC declaratory judgment to address the treatment of any expired balance under the 3% soft cap provisions. A decision is pending.

~~As of March 31, 2023, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021, 2022 and the first quarter of 2023 results.~~

~~Transmission Cost Adjustment —~~ ~~In December 2022, the CPUC suspended PSCo’s~~ request for 2023 TCA rate changes. The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of existing infrastructure should be included. The CPUC consolidated the matter with the pending electric rate case for assessment.

~~ECA Fuel Recovery —~~ In December 2022, PSCo filed its first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of one quarter, as more typical). In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates, and required PSCo to file a separate application to recover these costs.

In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs and collections commenced on March 1, 2023. The remaining $53 million of under-recovered costs consists of $25 million of ordinary fuel and purchased energy costs and $28 million costs attributable to coal curtailments resulting from rail transportation labor shortages. PSCo expects to make filings in the second quarter regarding the prudence of costs associated with coal curtailments, and to request that recovery of the remaining $25 million of ordinary fuel and purchased energy costs commence in the third quarter.

~~GCA NOPR~~— ~~In June 2021, the CPUC issued a NOPR addressing the~~ recovery of costs ~~through~~to execute the GCA. The CPUC has proposed a 2-step process aimed at 1) considering near term process changes to the GCA and 2) a longer-term process to evaluate potential performance incentive structures. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration. PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own PIM in a future filing. In December 2022, the CPUC approved the consensus proposal. PSCo expects to file its proposed PIMplan in the second quarter of ~~2023.~~2024. The plan will include a number of new and expanded programs from the currently approved Wildfire Mitigation Plan including distribution undergrounding, distribution covered conductor, enhanced wildfire safety settings, increased scope and scale for vegetation management, updated frequency of inspections of poles and other equipment in wildfire risk zones, transmission line rebuilds, proactive line de-energization and situational awareness programs including weather stations, cameras, and other monitoring software.

2426

Table of Contents

CPUC Proactive Line De-Energization Investigation —In ~~February 2023,~~early April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 MPH to reduce potential wildfire risk. Later in April, the ~~Governor of Colorado issued an open letter~~CPUC opened a Miscellaneous Proceeding to seek information on:

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

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

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

The CPUC held sessions to ~~take additional steps~~hear public comments and will hold Commissioner Information Meetings in May 2024 to ~~address energy costs. It is likely this request will result in the opening of additional dockets to further explore the GCA~~hear directly from PSCo, impacted customers, and other ~~related mechanisms. Additionally, the~~ first responders and community leaders on power shutoffs. A potential order, rules, procedures or report is expected later this year.

Colorado ~~Legislature formed a Joint Select Committee to investigate the source of rising utility rates~~Legislation — In May 2023, Colorado Senate Bill 23-291 passed and ~~explore potential actions to prevent future price instability. Legislation has been introduced by members of the Joint Select Committee on~~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).

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

The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. In the first quarter of ~~2023, final~~2024, the CPUC discussed proposed rules ~~were issued to implement recent state legislation requiring natural~~for the gas ~~utilities to develop clean heat plans to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally,~~utility. The written notice of the rules included new comprehensive natural gas infrastructure planning requirements and Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans.

~~Real-Time Energy Imbalance Market —~~ ~~In April 2023, PSCo joined the SPP Western Energy Imbalance Service market which balances generation and load regionally and in real time for participants~~proposed rule is expected in the ~~Western Interconnection. PSCo’s participation~~second quarter of 2024, which will be followed by a comment period. The Commission's proposed rules for electric utilities are expected later in ~~the SPP Western Energy Imbalance Service market replaces its joint dispatch agreement while extending the geographic area for which energy sales are made.~~2024.

SPS

Pending and Recently Concluded Regulatory Proceedings

~~SPS — 2022 New Mexico Electric Rate Case~~ — In November 2022, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $78 million, or 10%. The request is based on a FTY ending June 30, 2024, a ROE of 10.75%, an equity ratio of 54.7% and rate base of $2.4 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2032 to 2028. In March 2023, the NMPRC issued an Order extending the suspension period by one month. Additionally, SPS filed a supplemental filing, which decreased the requested increase to $76 million.

~~On April 21, 2023, the following parties filed testimony: NMPRC Staff, OPL, AG, NMLCG, LES-FEA and Walmart, with all except Walmart providing a proposed revenue change.~~

(Millions of Dollars) NMPRC Staff OPL AG NMLCG LES-FEA
SPS direct testimony $ 76 $ 76 $ 76 $ 76 $ 76
Recommended base rate adjustments:
Test year present revenues and allocators (1) 2 (1) 1 (47)
ROE (a)
(24) (29) (37) (29) (21)
Capital structure — (22) — (22) —
Adjustment to FTY plant additions/rate base items — (4) (10) (5) —
Tolk Generating Station depreciation expense — (7) — (7) (11)
Other, net (14) (1) (19) (13) —
Total adjustments (39) (61) (67) (75) (79)
Total proposed revenue change $ 37 $ 15 $ 9 $ 1 $ (3)

~~(a)AG recommends a reduction of $37 million reflecting its combined recommendation for ROE and capital structure.~~

Recommended Position NMPRC Staff OPL AG NMLCG LES-FEA Walmart
ROE 9.35 % 8.70 % 9.00 % 8.70 % 9.40 % 9.61 %
Equity Ratio 54.70 45.00 50.57 45.00 54.70 N/A

~~The next steps in the revised procedural schedule are as follows:~~

•~~Rebuttal testimony: May 10, 2023.~~

•~~Stipulation: May 17, 2023.~~

•~~Hearing: June 20, 2023.~~

•~~End of rate suspension: Oct. 19, 2023.~~

2023 Texas Electric Rate Case — In ~~February~~ 2023, SPS filed an electric rate case with the ~~Public Utility Commission of Texas (PUCT)~~PUCT seeking an increase in base rate revenue of ~~$149 million (13%). In March 2023, SPS updated the filing based on a historical test year period ended Dec. 31, 2022, which increased the rate revenue request to~~ $158 million (14% ~~impact to customer bills)~~). The request iswas based on a ROE of 10.65%, an equity ratio of 54.6% ~~and~~, a retail rate base of $3.6 ~~billion. Additionally, the request reflects further acceleration of~~billion and a change in the Tolk coal plant depreciation life from 2034 to 2028.

In December 2023, SPS, ~~is requesting~~PUCT Staff and intervenors filed a ~~surcharge from July 13, 2023 through the effective date of new base rates.~~

~~Next steps in the procedural schedule are as follows:~~black box settlement. Key terms include:

•~~Intervenor direct testimony: August 4,~~A base rate increase of $65 million effective back to July 13, 2023.

•~~Staff direct testimony: August 11, 2023.~~A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.

•~~Rebuttal testimony: August 25, 2023.~~The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.

•~~Hearings: Sept. 12-21, 2023.~~Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses.

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

•2022 All-Source RFP ~~Proposed findings: Oct. 25, 2023.~~

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

~~SPS and LP&L Contract Termination~~ — SPS and LP&L have a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (to the benefit of SPS’ remaining customers). LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The agreement has received PUCT approval and is pending FERC approval.mid-2024.

~~2022 All-Source RFP~~ ~~— In 2022, SPS issued an RFP, which seeks up to 947 MW~~The second portion of ~~new or existing capacity resources to provide replacement capacity for retiring units and meet SPS’ growing capacity needs through 2027. SPS has received bids and is currently reviewing~~ the ~~proposals. SPS will file~~portfolio includes a November 2023 filing for the approval of ~~successful proposals~~PPAs including 48 MW of battery energy storage and 230 MW of existing gas generation. Regulatory decisions on these PPA agreements are expected in the third quarter of ~~2023.~~2024.

~~Texas Fuel Reconciliation~~New Mexico Resource Plan — In ~~2021,~~October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. Based on load forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging from approximately 5,300 MW to ~~recover $88 million~~10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP. SPS expects to issue an RFP for new generation in July 2024. The RFP will be evaluated in the latter half of ~~Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing,~~2024 with total under-recovered costs of $121 million. In April 2022, interim rates designed to recover $121 million over 30 months were approved, subject to PUCT approval through the triennial Fuel Reconciliation proceeding.portfolio selection expected in early 2025.

In November 2022, the ALJs found that costs were prudently incurred and recommended no disallowances. In March 2023, the PUCT issued a Final Order which fully adopted the recommended decision with no disallowances of costs.

~~Table of Contents~~

Other

Supply Chain

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

~~Electric Meters and Transformers~~

Supply chain issues associated with semi-conductors have delayed the availability of advanced infrastructure meters, which led to a reduced number of meters deployed in 2022. While we have seen improvements in the 2023 deployment plan, the supply chain challenges persist. Full 2023 impacts and mitigation plans are currently being evaluated.

Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases may result in delays in projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the future. Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate impacts of supply constraints.

Solar Resources

In ~~April 2022,~~August 2023, the U.S. Department of Commerce ~~initiated an~~completed its anti-circumvention investigation and concluded that ~~would subject~~ CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia ~~with potential~~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 ~~has been issued~~remains in effect until June 2024 and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports ~~(i.e.~~(e.g., as a result of implementation of the Uyghur Forced Labor Protection Act), disruptions in solar imports from key suppliers or any new trade complaint could impact project timelines and costs.

~~Marshall Wildfire~~

~~In December 2021,~~On April 24, 2024, the American Alliance for Solar Manufacturing Trade Committee filed a ~~wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres~~petition related to new anti-dumping and ~~destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire~~countervailing duty cases targeting solar products from Cambodia, Malaysia, Thailand and ~~have not yet determined a cause. There were no downed power lines in the ignition area, and nothing PSCo has seen to this point indicates that our equipment or operations caused the fire.~~

In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistentVietnam with the ~~practical conduct~~United States Department of Commerce and the United States International Trade Commission. Xcel Energy continues to assess the impacts (if any) of this trade complaint on its business.

Table of Contents


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 ~~liability does not extend~~results reported. Items considered critical, in addition to ~~occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under~~the matter noted below, are included within the Xcel Energy Inc. Annual Report on Form 10-K ~~a commission approved wildfire mitigation plan~~for the year ended Dec. 31, 2023.

Loss Contingencies – Wildfires

The outcomes of legal proceedings and ~~carries wildfire liability insurance.~~

~~In March 2022, a class action suit was filed in Boulder County pertaining~~claims brought against Xcel Energy related to the Marshall ~~Fire. In~~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 ~~remote event Xcel Energy Inc. or PSCo was found liable related~~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 ~~this litigation~~make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and ~~were required to pay~~future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages ~~such amounts could exceed our insurance coverage~~ and ~~have a material adverse effect on our~~the status of investigations and legal proceedings are considered. See Note 10 accompanying the consolidated financial condition, results of operations or cash flows. In December 2022, the District Court judge denied our Motion to Dismiss. An evidentiary hearing regarding our request to dismiss Xcel Energy, Inc. from the suit is scheduledstatements for ~~May 2023.~~

~~MISO Capacity Credits —~~ The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing and is expected to generate revenues of approximately $90 million in 2022 and approximately $60 million in 2023. During the three months ended March 31, 2023, the NSP System received approximately $40 million of capacity credits. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.additional information.

Environmental Regulation

Clean Air Act

~~NOx Allowance Allocations —~~Power Plant Greenhouse Gas Regulations —In ~~March 2023, after disapproving state implementation plans,~~April 2024, the EPA ~~released a prepublication version~~published final rules addressing control of CO2 emissions from the ~~final regulations under the "Good Neighbor" provisions~~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 ~~the Clean Air Act.~~coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. 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 impactCO2 control requirements vary by subcategory. Xcel Energy ~~fossil fuel-fired electric generating facilities in~~continues to evaluate the ~~states within our service territory. Applicable facilities will have to secure additional allowances, install NOx controls and/~~impact of these rules and believes that the cost of these initiatives 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~~replacement generation ~~Xcel Energy anticipates the annual costs could be significant, but~~ would be recoverable through ~~regulatory mechanisms.~~

~~SPS and NSP-Minnesota have joined other impacted companies in litigation challenging the EPA’ disapproval of Texas and Minnesota~~rates based on prior state ~~implementation plans.~~commission practices.

~~GHG Emissions Limits~~Waste-to-Energy Air Regulations — ~~It is anticipated~~In January 2024, the EPA proposed air regulations addressing new and existing large municipal waste combustors. The proposed rules lower current emission standards for certain pollutants and would require installation of new pollution controls and/or more intense use of existing pollution controls at French Island Generating Station. Until final rules are issued, it is not certain what the impact will propose rules to limit GHG emissions from new fossil fuel-fired electric generating units and natural gas-fired stationary combustion units under Clean Air Act Section 111(b) as well as emission guidelines under Clean Air Act Section 111(d) to limit GHG emissions from existing fossil fuel-fired electric generating units in 2023.

~~If any new rules require additional investment,~~be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

Coal Ash Regulation

In ~~February 2023,~~April 2024, the EPA ~~entered into a Consent Decree committing the agency to either issue new proposed~~published final rules ~~by May 5, 2023,~~ to regulate ~~inactive CCR landfills~~additional areas under the CCR Rule for the first time, orincluding legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities. The rule subjects these areas to ~~determine no such rules are necessary by that date.~~

~~If proposed rules are issued,~~groundwater monitoring, corrective action and closure and post-closure care requirements, among other requirements, with several of the ~~EPA has committed to a May 2024 effective date for those new rules. It is also anticipated~~deadlines accelerated. Xcel Energy believes that the ~~EPA may issue other~~cost of these requirements would be recoverable through rates based on prior state commission practices. In January 2024, PSCo received approval from the CPUC for deferred accounting for costs associated with compliance with the legacy CCR ~~proposed rules in 2023 that further expand the scope of~~

~~the CCR Rule. Until proposed rules are issued, it is not certain what the impact will be on Xcel Energy.~~rule.

Emerging Contaminants of Concern

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

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

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

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

Final rules for all three proposals are expected in 2024 which could result in new ~~obligations for investigation and cleanup. Xcel Energy~~obligations. Potential costs are uncertain until final rules are published and/or agency action is ~~monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.~~taken.

Effluent Limitation Guidelines

In ~~March 2023,~~April 2024, the EPA ~~released a proposed rule~~published final rules under the Clean Water Act, setting forth ~~proposed~~ Effluent Limitations Guidelines and Standards for steam generating coal plants. This ~~proposed~~ 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. ~~Comments~~Xcel Energy continues to evaluate the ~~proposed regulations are due May 30, 2023. The~~ impact of these ~~proposed regulations is uncertain.~~rules and believes that any costs associated with these requirements would be recoverable through rates based on prior state commission practices.


Derivatives, Risk Management and Market Risk

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

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

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

Table of Contents

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

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

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

Fair value of net commodity trading contracts as of March 31, ~~2023:~~2024:


			Futures / Forwards Maturity
		Futures / Forwards Maturity																Futures / Forwards Maturity
(Millions of Dollars)	(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year	1 to 3 Years	4 to 5 Years	Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	NSP-Minnesota (a)		$	(2)	$	(3)	$	(6)	$	(1)	$	(12)
NSP- Minnesota (b)	NSP- Minnesota (b)		(2)		(7)		(2)		(2)		(13)
PSCo (a)
PSCo ~~(a)~~(b)	PSCo ~~(a)~~(b)		4		1		3		—		8
PSCo (b)			(42)		3		2		—		(37)
			$	(42)	$	(6)	$	(3)	$	(3)	$	(54)
		$


			Options Maturity
		Options Maturity																Options Maturity
(Millions of Dollars)	(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year	1 to 3 Years	4 to 5 Years	Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	NSP-Minnesota (b)		$	—	$	—	$	3	$	15	$	18
PSCo (b)	PSCo (b)		33		1		—		—		34
			$	33	$	1	$	3	$	15	$	52
		$

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

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

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


(Millions of Dollars)	(Millions of Dollars)	2023		2022		(Millions of Dollars)	2024	2023
Fair value of commodity trading net contracts outstanding at Jan. 1	Fair value of commodity trading net contracts outstanding at Jan. 1	$	(33)	$	(33)
Contracts realized or settled during the period	Contracts realized or settled during the period	3		3
Commodity trading contract additions and changes during the period	Commodity trading contract additions and changes during the period	28		9
Fair value of commodity trading net contracts outstanding at March 31	Fair value of commodity trading net contracts outstanding at March 31	$	(2)	$	(21)

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 ~~an immaterial amount and~~ approximately $4 million at March 31, ~~2023,~~2024 and ~~approximately $14 million and $17 million at~~ March 31, ~~2022. Market price movements can exceed 10% under abnormal circumstances.~~2023.

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

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


(Millions of Dollars)	(Millions of Dollars)	Three Months Ended March 31		Average		High		Low		(Millions of Dollars)	Three Months Ended March 31	Average	High	Low
2024
2023	2023	$	0.6	$	0.7	$	1.1	$	0.4
2022		1.1		1.0		1.3		0.7

~~Table of Contents~~

Nuclear Fuel Supply — ~~NSP-Minnesota has contracted for its 2023, 2024 and 2025 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. NSP-Minnesota~~NSP-Minnesota is scheduled to take delivery of approximately ~~26%~~29% of its average ~~enriched~~enriched nuclear material requirements from Russia through 2030. Given the evolving situation in Ukraine and its global impacts, we have entered into additional ~~new~~ contracts that cover potential supply interruptions of nuclear material from Russia. With these contracts, NSP-Minnesota has secured its enriched nuclear material requirements through 2028 with non-Russian material, which are in various stages of processing in Canada, Europe and the United States.

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

A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately ~~$11~~$8 million and ~~$12~~$11 million in March 31, ~~2023~~2024 and ~~2022,~~2023, respectively.

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

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

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

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

At March 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $25 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At March 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $37 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $36 million. ~~At March 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure~~

Table of ~~$39 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $28 million.~~Contents

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~~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 ~~Notes~~Note 8 ~~and 9~~ to the consolidated financial statements for further information.


~~LIQUIDITY AND CAPITAL RESOURCES~~Liquidity and Capital Resources

Cash Flows

Operating Cash Flows


(Millions of Dollars)	Three Months Ended March 31
Cash provided by operating activities — ~~2022~~2023	$	~~1,140~~1,537

Components of change — ~~2023~~2024 vs. ~~2022~~2023
Higher net income	3870

~~Non-cash transactions~~Changes in deferred income taxes	53227
Changes in working capital	~~211~~ (438)
Changes in net regulatory and other assets and liabilities	95 (346)
Cash provided by operating activities — ~~2023~~2024	$	~~1,537~~1,050

Net cash provided by operating activities ~~increased $397~~decreased $487 million for the three months ended March 31, ~~2023~~2024 compared with the prior year. The ~~increase~~decrease was ~~primarily~~largely due to interim rate refunds in Minnesota, as well as the impact of ~~decreasing~~decreased natural gas prices on ~~customer receivables and~~ accounts payable ~~as well as continued collections~~and receivables, partially offset by the change in deferred income taxes, which includes the impact of ~~deferred net natural gas, fuel and purchased energy costs incurred during Winter Storm Uri.~~proceeds for tax credit transfers.

Investing Cash Flows


(Millions of Dollars)	Three Months Ended March 31
Cash used in investing activities — ~~2022~~2023	$	~~(952)~~(1,284)

Components of change — ~~2023~~2024 vs. ~~2022~~2023
Increased capital expenditures	~~(323)~~(272)

~~Other investing activities~~	~~(9)~~
Cash used in investing activities — ~~2023~~2024	$	~~(1,284)~~(1,556)

Net cash used in investing activities increased ~~$332~~$272 million for the three months ended March 31, ~~2023~~2024 compared with the prior year. The increase in capital expenditures was largely due to continued system ~~expansion.~~expansion and increased investment in renewable projects.

Financing Cash Flows


(Millions of Dollars)	Three Months Ended March 31
Cash used in financing activities — ~~2022~~2023	$	~~(264)~~(250)

Components of change — ~~2023~~2024 vs. ~~2022~~2023
Higher net short-term debt proceeds	~~275~~ (588)
~~Lower net long-term debt repayments~~	~~(250)~~
Higher ~~proceeds from issuance~~long-term debt issuances, net of ~~common stock~~repayments	51,728


Other financing activities	~~(16)~~(12)
Cash ~~used in~~provided by financing activities — ~~2023~~2024	$	~~(250)~~878

Net cash ~~used~~provided by financing activities ~~decreased $14~~increased $1,128 million for the three months ended March 31, ~~2023~~2024 compared with the prior year. The ~~decrease~~increase was largely related to the amount/timing of debt issuances and repayments.

~~Table of Contents~~

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 ~~2023,~~2024, contributions of ~~$50~~$100 million were made across four of Xcel Energy’s pension plans.

•In ~~2022,~~2023, contributions of $50 million were made across four of Xcel Energy’s pension plans.

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

Capital Sources

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

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

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

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As of April ~~24, 2023,~~22, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity		(Millions of Dollars)	Credit Facility (a)	Drawn (b)	Available	Cash	Liquidity
Xcel Energy Inc.	Xcel Energy Inc.	$	1,500	$	367	$	1,133	$	1	$	1,134
PSCo	PSCo	700		27		673		155		828
NSP-Minnesota	NSP-Minnesota	700		92		608		4		612
SPS	SPS	500		55		445		2		447
NSP-Wisconsin	NSP-Wisconsin	150		30		120		1		121
Total	Total	$	3,550	$	571	$	2,979	$	163	$	3,142

(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. ~~The~~As of March 31, 2024, the authorized levels for these commercial paper programs are:

•$1.5 billion for Xcel Energy Inc.

•$700 million for PSCo.

•$700 million for NSP-Minnesota.

•$500 million for SPS.

•$150 million for NSP-Wisconsin.

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

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

~~2023~~2024 Planned Financing Activity — ~~During 2023,~~ Xcel ~~Energy~~Energy’s 2024 financing plans ~~to issue approximately $85 million of equity through~~reflect the ~~DRIP and benefit programs. Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:~~following:

Issuer

Security

Amount

Status

Tenor

Coupon

Issuer

Security

Amount

Status

Tenor

Coupon

Xcel Energy Inc.

Senior Unsecured Notes

800

million

Completed

10 Year

5.50

NSP-Minnesota

First Mortgage Bonds

700

million

Completed

30 Year

5.40

PSCo

First Mortgage Bonds

850

million

Completed (a)

30 Year

5.25%

PSCo

First Mortgage Bonds

1,200

million

Completed (a)

10 Year & 30 Year

5.35 % & 5.75 %

SPS

First Mortgage Bonds

600

million

Second Quarter

30 Year

N/A

NSP-Wisconsin

First Mortgage Bonds

125

million

Second Quarter (b)

30 Year

5.30

NSP-Wisconsin

First Mortgage Bonds

400

million

Second Quarter

30 Year

N/A

NSP-Minnesota

First Mortgage Bonds

800

million

Second Quarter

N/A

Xcel Energy

Unsecured Senior Notes

500

million

Third Quarter

N/A

SPS

First Mortgage Bonds

100

million

Third Quarter

N/A

(a)Bond was issued on April ~~3, 2023.~~4, 2024.

~~(b)~~Long-Term Borrowings, Equity Issuances and Other Financing Instruments~~NSP-Wisconsin priced a 30-year first mortgage bond on April 21, 2023 and will close on the proceeds in June 2023.~~

— Xcel Energy may issue equity through its at-the-market program or other offerings. Financing plans are subject to change, depending on ~~legislative initiatives (e.g., federal tax law changes),~~ capital expenditures, ~~the development of a tax credit transferability market,~~ 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 ~~2023~~2024 Earnings Guidance — Xcel Energy’s ~~2023 GAAP and~~2024 ongoing earnings guidance is a range of ~~$3.30~~$3.50 to ~~$3.40~~$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%~~1% to 2%.

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

•Capital rider revenue is projected to increase ~~$70~~$60 million to ~~$80~~$70 million (net of PTCs). ~~The change from the previous estimate is largely due to a change in the projected levels of PTCs, which are offset in the ETR and largely earnings neutral.~~

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

•Depreciation expense is projected to increase approximately ~~$130~~$290 million to ~~$140~~$300 million. The change largely reflects changes in depreciation rates approved in the Texas rate case, which are largely offset in revenue and earnings neutral.

•Property taxes are projected to increase ~~approximately $30~~$20 million to ~~$40~~$30 million.

•Interest expense (net of AFUDC - debt) is projected to increase ~~$100~~$165 million to ~~$110 million.~~$175 million, net of interest income.

•AFUDC - equity is projected to increase $0$65 million to ~~$10~~$75 million.

•ETR is projected to be ~~~(7%~~~(4%) to ~~(9%~~(6%). The ~~change from the previous estimate~~negative ETR is largely ~~due~~offset by PTCs flowing back to ~~a change in the projected levels of PTCs, which are offset~~customers in the capital riders and fuel mechanisms and ~~are~~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 ~~forecast if~~quantify the financial impacts of any ~~of these items will~~additional adjustments that may occur orfor 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 ~~2022~~2023 actual ongoing earnings base of ~~$3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20~~$3.35 per share.

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

• Target a dividend payout ratio of ~~60%~~50% to ~~70%~~60%.

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

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

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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, ~~2022~~2023 under “Derivatives, Risk Management and Market Risk.”


ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

As of March 31, ~~2023,~~2024, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

PART II — OTHER INFORMATION


ITEM 1 — LEGAL PROCEEDINGS

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

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

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


ITEM 1A — RISK FACTORS

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, ~~2022,~~2023, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

~~Table of Contents~~


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

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:

The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended March 31, ~~2023:~~2024:

Issuer Purchases of Equity Securities
Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2023 - Jan. 31, 2023 — $ — — —
Feb. 1, 2023 - Feb. 28, 2023 — — — —
March 1, 2023 - March 31, 2023 (a)
795 64.57 — —
795 — —


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

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


ITEM 5 — OTHER INFORMATION

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

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ITEM 6 — EXHIBITS


*			Indicates incorporation by reference


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012	Xcel Energy Inc. Form 8-K dated May 16, 2012	3.01
3.02*	Bylaws of Xcel Energy Inc., as Amended and Restated on ~~April 3, 2020~~August 23, 2023	Xcel Energy Inc Form 8-K dated ~~April 3, 2020~~August 23, 2023	~~3.01~~3.02
4.01*	Supplemental Indenture No. 3418, dated as of February 29, 2024 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $800,000,000 aggregate principal amount of 5.50% Senior Notes, Series due March 15, 2034.	Xcel Energy Inc Form 8-K dated February 29, 2024	4.01
4.0 2*	Supplemental Trust Indenture dated as of February 1, ~~2023,~~2024 between ~~PSCo~~Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700,000,000 aggregate principal amount of 5.40% First Mortgage Bonds, Series due March 15, 2054.	NSP-Minnesota Form 8-K dated February 29, 2024	4.01
4.03*	Supplemental Indenture dated as of April 1, 2024, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating ~~$850~~$450 million ~~aggregate~~ principal amount of ~~5.25%~~5.35% First Mortgage Bonds, Series No. 4041 due ~~April 1, 2053~~2034 and $750 million principal amount of 5.75% First Mortgage Bonds, Series No. 42 due 2054.	PSCo Form 8-K dated April ~~3, 2023~~4, 2024	4.01
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002.~~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.~~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.~~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.~~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)

3133

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SIGNATURES

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


		XCEL ENERGY INC.

4/~~27/2023~~25/2024	By:	/s/ MELISSA L. OSTROM
		Melissa L. Ostrom
		Vice President, Controller
		(Principal Accounting Officer)


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

3234


(Millions of Dollars)	NMPRC Staff		OPL		AG		NMLCG		LES-FEA
SPS direct testimony	$	76	$	76	$	76	$	76	$	76

Recommended base rate adjustments:
Test year present revenues and allocators	(1)		2		(1)		1		(47)
ROE (a)	(24)		(29)		(37)		(29)		(21)
Capital structure	—		(22)		—		(22)		—
Adjustment to FTY plant additions/rate base items	—		(4)		(10)		(5)		—
Tolk Generating Station depreciation expense	—		(7)		—		(7)		(11)




Other, net	(14)		(1)		(19)		(13)		—
Total adjustments	(39)		(61)		(67)		(75)		(79)
Total proposed revenue change	$	37	$	15	$	9	$	1	$	(3)