
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
EPA			United States Environmental Protection Agency
FERC			Federal Energy Regulatory Commission


MPUC			Minnesota Public Utilities Commission
NMPRC			New Mexico Public Regulation Commission

NRC			Nuclear Regulatory Commission
OAG			Minnesota Office of Attorney General
PSCW			Public Service Commission of Wisconsin
PUCT			Public Utility Commission of Texas
SEC			Securities and Exchange Commission
SDPUC			South Dakota Public Utilities Commission


Electric, Purchased Gas and Resource Adjustment Clauses
ECA			Retail electric commodity adjustment
GCA			Gas cost adjustment


Other
AFUDC			Allowance for funds used during construction

ALJ			Administrative Law Judge
ATM			At-the-market
BART			Best available retrofit technology
C&I			Commercial and Industrial
CCR			Coal combustion residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste


CDD			Cooling degree-days
CEO			Chief executive officer
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFO			Chief financial officer
CORE			CORE Electric Cooperative
CSPV			Crystalline Silicon Photovoltaic
DRIP			Dividend Reinvestment and Stock Purchase Program
EPS			Earnings per share
ETR			Effective tax rate
FTR			Financial transmission right

GAAP			United States generally accepted accounting principles
GE			General Electric Company
HDD			Heating degree-days
IPP			Independent power producing entity
LDC			Local distribution company
LLC			Limited liability company
LP&L			Lubbock Power and Light
MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator, Inc.
NAV			Net asset value
NOPR			Notice of Proposed Rulemaking
NOx			Nitrogen Oxides
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
PFAS			Per- and Polyfluoroalkyl Substances
PIM			Performance Incentive Mechanism
PPA			Power purchase agreement
PTC			Production tax credit
RFP			Request for proposal
ROE			Return on equity
RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.
TCA			Transmission cost adjustment
THI			Temperature-humidity index
TOs			Transmission owners
VaR			Value at Risk


Measurements
MW			Megawatts

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 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2022 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 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 threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.


	Six Months Ended June 30
	2023		2022
Operating activities
Net income	$	706	$	708
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,202		1,210
Nuclear fuel amortization	53		61
Deferred income taxes	(192)		(135)
Allowance for equity funds used during construction	(37)		(33)
Earnings from equity method investments	(20)		(26)
Dividends from equity method investments	18		20
Provision for bad debts	36		30
Share-based compensation expense	12		14
Changes in operating assets and liabilities:
Accounts receivable	225		(97)
Accrued unbilled revenues	364		70
Inventories	100		(44)
Other current assets	39		26
Accounts payable	(443)		137
Net regulatory assets and liabilities	569		213
Other current liabilities	(74)		(134)
Pension and other employee benefit obligations	(37)		(32)
Other, net	(66)		—
Net cash provided by operating activities	2,455		1,988

Investing activities
Capital/construction expenditures	(2,599)		(2,040)
Purchase of investment securities	(416)		(787)
Proceeds from the sale of investment securities	399		769
Other, net	(23)		3
Net cash used in investing activities	(2,639)		(2,055)

Financing activities
Repayments of short-term borrowings, net	(269)		(869)
Proceeds from issuances of long-term debt	1,741		2,066
Repayments of long-term debt, including reacquisition premiums	(650)		(600)
Proceeds from issuance of common stock	75		151
Dividends paid	(536)		(497)
Other, net	(13)		(15)
Net cash provided by financing activities	348		236

Net change in cash, cash equivalents and restricted cash	164		169
Cash, cash equivalents and restricted cash at beginning of period	111		166
Cash, cash equivalents and restricted cash at end of period	$	275	$	335

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(461)	$	(425)
Cash paid for income taxes, net	(49)		(9)

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	497	$	401
Inventory transfers to property, plant and equipment	78		30
Operating lease right-of-use assets	50		15
Allowance for equity funds used during construction	37		33
Issuance of common stock for reinvested dividends and/or equity awards	32		27


See Notes to Consolidated Financial Statements


	June 30, 2023		Dec. 31, 2022
Assets
Current assets
Cash and cash equivalents	$	275	$	111
Accounts receivable, net	1,111		1,373
Accrued unbilled revenues	741		1,105
Inventories	625		803
Regulatory assets	828		1,059
Derivative instruments	233		279
Prepaid taxes	66		54
Prepayments and other	322		360
Total current assets	4,201		5,144

Property, plant and equipment, net	49,664		48,253

Other assets
Nuclear decommissioning fund and other investments	3,456		3,234
Regulatory assets	2,632		2,871
Derivative instruments	80		93
Operating lease right-of-use assets	1,143		1,204
Other	482		389
Total other assets	7,793		7,791
Total assets	$	61,658	$	61,188

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,051	$	1,151
Short-term debt	544		813
Accounts payable	1,307		1,804
Regulatory liabilities	486		418
Taxes accrued	407		569
Accrued interest	233		217
Dividends payable	287		268
Derivative instruments	65		76
Operating lease liabilities	226		217
Other	625		545
Total current liabilities	5,231		6,078

Deferred credits and other liabilities
Deferred income taxes	4,657		4,756
Deferred investment tax credits	46		48
Regulatory liabilities	5,752		5,569
Asset retirement obligations	3,295		3,380
Derivative instruments	99		113
Customer advances	174		181
Pension and employee benefit obligations	353		390
Operating lease liabilities	966		1,038
Other	156		147
Total deferred credits and other liabilities	15,498		15,622

Commitments and contingencies
Capitalization
Long-term debt	24,015		22,813
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 551,375,255 and 549,578,018 shares outstanding at June 30, 2023 and December 31, 2022, respectively	1,378		1,374
Additional paid in capital	8,247		8,155
Retained earnings	7,371		7,239
Accumulated other comprehensive loss	(82)		(93)
Total common stockholders’ equity	16,914		16,675
Total liabilities and equity	$	61,658	$	61,188

See Notes to Consolidated Financial Statements


	Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
	Shares	Par Value		Additional Paid In Capital
Three Months Ended June 30, 2023 and 2022
Balance at March 31, 2022	544,530,987	$	1,361	$	7,801	$	6,686	$	(116)	$	15,732
Net income						328				328
Other comprehensive income								13		13
Dividends declared on common stock ($0.4875 per share)						(266)				(266)
Issuances of common stock	2,276,806	6		153						159

Share-based compensation				6		(1)				5
Balance at June 30, 2022	546,807,793	$	1,367	$	7,960	$	6,747	$	(103)	$	15,971

Balance at March 31, 2023	550,222,192	$	1,376	$	8,169	$	7,370	$	(97)	$	16,818
Net income						288				288
Other comprehensive income								15		15
Dividends declared on common stock ($0.52 per share)						(286)				(286)
Issuances of common stock	1,153,063	2		75						77

Share-based compensation				3		(1)				2
Balance at June 30, 2023	551,375,255	$	1,378	$	8,247	$	7,371	$	(82)	$	16,914

	Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
	Shares	Par Value		Additional Paid In Capital
Six Months Ended June 30, 2023 and 2022
Balance at Dec. 31, 2021	544,025,269	$	1,360	$	7,803	$	6,572	$	(123)	$	15,612
Net income						708				708
Other comprehensive income								20		20
Dividends declared on common stock ($0.975 per share)						(531)				(531)
Issuances of common stock	2,782,524	7		164						171

Share-based compensation				(7)		(2)				(9)

Balance at June 30, 2022	546,807,793	$	1,367	$	7,960	$	6,747	$	(103)	$	15,971

Balance at Dec. 31, 2022	549,578,018	$	1,374	$	8,155	$	7,239	$	(93)	$	16,675
Net income						706				706
Other comprehensive income								11		11
Dividends declared on common stock ($1.04 per share)						(572)				(572)
Issuances of common stock	1,797,237	4		91						95

Share-based compensation				1		(2)				(1)
Balance at June 30, 2023	551,375,255	$	1,378	$	8,247	$	7,371	$	(82)	$	16,914

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of June 30, 2023 and Dec. 31, 2022; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 2023 and 2022; and Xcel Energy’s cash flows for the six months ended June 30, 2023 and 2022.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2023, 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 balance sheet information has been derived from the audited 2022 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2022.

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, filed with the SEC on Feb. 23, 2023.

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 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

As of June 30, 2023, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy’s consolidated financial statements.


3. Selected Balance Sheet Data


(Millions of Dollars)	June 30, 2023		Dec. 31, 2022
Accounts receivable, net
Accounts receivable	$	1,232	$	1,495
Less allowance for bad debts	(121)		(122)
Accounts receivable, net	$	1,111	$	1,373


(Millions of Dollars)	June 30, 2023		Dec. 31, 2022
Inventories
Materials and supplies	$	354	$	330
Fuel	199		201
Natural gas	72		272
Total inventories	$	625	$	803


(Millions of Dollars)	June 30, 2023		Dec. 31, 2022
Property, plant and equipment, net
Electric plant	$	50,816	$	49,639
Natural gas plant	8,777		8,514
Common and other property	3,081		2,970
Plant to be retired (a)	2,148		2,217
Construction work in progress	2,541		2,124
Total property, plant and equipment	67,363		65,464
Less accumulated depreciation	(18,032)		(17,502)
Nuclear fuel	3,278		3,183
Less accumulated amortization	(2,945)		(2,892)
Property, plant and equipment, net	$	49,664	$	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 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.

Commercial paper and term loan borrowings outstanding for Xcel Energy:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2023			Year Ended Dec. 31, 2022
Borrowing limit	$	3,550		$	3,550
Amount outstanding at period end	544			813
Average amount outstanding	516			552
Maximum amount outstanding	1,078			1,357
Weighted average interest rate, computed on a daily basis	5.26		%	1.47		%
Weighted average interest rate at period end	5.32			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 $46 million and $43 million of letters of credit outstanding under the credit facilities at both June 30, 2023 and Dec. 31, 2022. Amounts approximate their fair value and are subject to fees.

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

As of June 30, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	$	1,500	$	476	$	1,024
PSCo	700		29		671
NSP-Minnesota	700		15		685
SPS	500		70		430
NSP-Wisconsin	150		—		150
Total	$	3,550	$	590	$	2,960

(a)Expires in September 2027.

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

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of June 30, 2023 and Dec. 31, 2022.

Bilateral Credit Agreement

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

As of June 30, 2023, NSP-Minnesota had $57 million of outstanding letters of credit under the $75 million bilateral credit agreement.

Long-Term Borrowings and Other Financing Instruments

During the six months ended June 30, 2023, Xcel Energy Inc. and its utility subsidiaries issued the following:

•PSCo issued $850 million of 5.25% first mortgage bonds due April 1, 2053.

•NSP-Wisconsin issued $125 million of 5.30% first mortgage bonds due June 15, 2053.

•NSP-Minnesota issued $800 million of 5.10% first mortgage bonds due May 15, 2053.

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares were issued (approximately $350 million). In 2022, 4.30 million shares of common stock were issued (approximately $300 million). In the six months ended June 30, 2023, 0.9 million shares were issued (approximately $62 million). As of June 30, 2023, approximately $88 million remained available for sale under the ATM program. Xcel Energy Inc. plans to file a new ATM program in 2023.

Equity through DRIP and Benefits Program — Xcel Energy issued $61 million and $45 million of equity through the DRIP and benefits programs during the six months ended June 30, 2023 and 2022, respectively. The programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.


5. Revenues

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


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


	Three Months Ended June 30, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	797	$	257	$	6	$	1,060
C&I	1,416		164		7		1,587
Other	37		—		9		46
Total retail	2,250		421		22		2,693
Wholesale	318		—		—		318
Transmission	156		—		—		156
Other	12		37		—		49
Total revenue from contracts with customers	2,736		458		22		3,216
Alternative revenue and other	187		18		3		208
Total revenues	$	2,923	$	476	$	25	$	3,424



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



	Six Months Ended June 30, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,614	$	919	$	15	$	2,548
C&I	2,651		520		9		3,180
Other	69		—		23		92
Total retail	4,334		1,439		47		5,820
Wholesale	577		—		—		577
Transmission	308		—		—		308
Other	35		82		—		117
Total revenue from contracts with customers	5,254		1,521		47		6,822
Alternative revenue and other	302		45		6		353
Total revenues	$	5,556	$	1,566	$	53	$	7,175


6. Income Taxes

Reconciliation between the statutory rate and ETR:


	Three Months Ended June 30				Six Months Ended June 30
	2023		2022		2023		2022
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	5.1		5.2		4.9		5.0
(Decreases) increases:
Wind PTCs (a)	(64.0)		(48.3)		(44.1)		(40.4)
Plant regulatory differences (b)	(6.3)		(5.5)		(5.8)		(5.1)
Other tax credits, net operating loss & tax credits allowances	(1.4)		(1.4)		(1.5)		(1.5)
Other (net)	1.6		(0.1)		0.5		(0.2)
Effective income tax rate	(44.0)	%	(29.1)	%	(25.0)	%	(21.2)	%

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

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


7. Earnings Per Share

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

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

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

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

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

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

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

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


	Three Months Ended June 30		Six Months Ended June 30
(Shares in Millions)	2023	2022	2023	2022
Basic	551	546	551	545
Diluted (a)	552	546	551	546

(a)Diluted common shares outstanding included common stock equivalents of 0.3 million for the three months ended June 30, 2023 and 2022, respectively. Diluted common shares outstanding included common stock equivalents of 0.2 million for the six months ended June 30, 2023 and 2022, respectively.


8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.

•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.

•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.

•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.

Specific valuation methods include:

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

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

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

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

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

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

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

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

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

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

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

Unrealized gains for the nuclear decommissioning fund were $1 billion as of June 30, 2023 and Dec. 31, 2022, and unrealized losses were $68 million and $90 million as of June 30, 2023 and Dec. 31, 2022, respectively.

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


	June 30, 2023
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	35	$	35	$	—	$	—	$	—	$	35
Commingled funds	736		—		—		—		1,061		1,061
Debt securities	780		—		724		8		—		732
Equity securities	508		1,248		2		—		—		1,250
Total	$	2,059	$	1,283	$	726	$	8	$	1,061	$	3,078

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $240 million of equity method investments and $138 million of rabbi trust assets and other miscellaneous investments.


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

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

For the three and six months ended June 30, 2023 and 2022, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of June 30, 2023:


	Final Contractual Maturity
(Millions of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	$	4	$	229	$	259	$	240	$	732

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 $84 million and $80 million at June 30, 2023 and Dec. 31, 2022, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Derivative Activities and Fair Value Measurements

Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.

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

As of June 30, 2023, accumulated other comprehensive loss related to interest rate derivatives included $2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of June 30, 2023, Xcel Energy had unsettled interest swaps outstanding with a notional amount of $345 million.

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

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

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

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

The most significant derivative positions outstanding at June 30, 2023 and Dec. 31, 2022 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 June 30, 2023, Xcel Energy had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards, options and FTRs:


(Amounts in Millions) (a)(b)	June 30, 2023	Dec. 31, 2022
Megawatt hours of electricity	93	61
Million British thermal units of natural gas	110	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 June 30, 2023, five of Xcel Energy’s ten most significant counterparties for these activities, comprising $68 million, or 29%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

Three of the ten most significant counterparties, comprising $55 million, or 24%, of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.

Two of these significant counterparties, comprising $58 million, or 25%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. Seven of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

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

As of June 30, 2023 and Dec. 31, 2022, there were $10 million and $4 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.

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

As of June 30, 2023 and Dec. 31, 2022, there were approximately $88 million and $76 million of derivative liabilities with such underlying contract provisions, respectively.

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

Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2023 and Dec. 31, 2022.

Recurring Derivative Fair Value Measurements

Impact of derivative activity:


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory Assets and Liabilities
Three Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	18	$	—
Total	$	18	$	—
Other derivative instruments:
Electric commodity	$	—	$	(19)
Natural gas commodity	—		—
Total	$	—	$	(19)

Six Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	11	$	—
Total	$	11	$	—
Other derivative instruments:
Electric commodity	$	—	$	(111)
Natural gas commodity	—		3
Total	$	—	$	(108)


Three Months Ended June 30, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	15	$	—
Total	$	15	$	—
Other derivative instruments:
Electric commodity	$	—	$	98
Natural gas commodity	—		(1)
Total	$	—	$	97

Six Months Ended June 30, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	22	$	—
Total	$	22	$	—
Other derivative instruments:
Electric commodity	$	—	$	100
Natural gas commodity	—		3
Total	$	—	$	103


	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and Liabilities
Three Months Ended June 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	(6)	(b)
Electric commodity	—			11		(c)	—

Total	$	—		$	11		$	(6)

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

Three Months Ended June 30, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	1	(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	7	(b)
Electric commodity	—			(26)		(c)	—

Total	$	—		$	(26)		$	7

Six Months Ended June 30, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	3	(a)	$	—		$	—
Total	$	3		$	—		$	—
Other derivative instruments:
Commodity trading	$	—		$	—		$	9	(b)
Electric commodity	—			(36)		(c)	—
Natural gas commodity	—			4		(d)	(17)		(d)(e)
Total	$	—		$	(32)		$	(8)

(a)Recorded to interest charges.

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

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

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

(e)Relates primarily to option premium amortization.

Xcel Energy had no derivative instruments designated as fair value hedges during the six months ended June 30, 2023 and 2022.

Changes in Level 3 commodity derivatives:


	Three Months Ended June 30
(Millions of Dollars)	2023		2022
Balance at April 1	$	78	$	39
Purchases (a)	167		390
Settlements (a)	(47)		(155)
Net transactions recorded during the period:
Gains recognized in earnings (b)	10		78
Net gains recognized as regulatory assets and liabilities (a)	1		133
Balance at June 30	$	209	$	485

	Six Months Ended June 30
(Millions of Dollars)	2023		2022
Balance at Jan. 1	$	235	$	19
Purchases (a)	172		394
Settlements (a)	(76)		(181)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)	(2)		120
Net (losses) gains recognized as regulatory assets and liabilities (a)	(120)		133
Balance at June 30	$	209	$	485

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

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

Fair Value of Long-Term Debt

As of June 30, 2023, other financial instruments for which the carrying amount did not equal fair value:


	June 30, 2023				Dec. 31, 2022
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	25,066	$	21,855	$	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 June 30, 2023 and Dec. 31, 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.


9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)



	Three Months Ended June 30
	2023		2022		2023		2022
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	18	$	25	$	—	$	1
Interest cost (a)	40		28		5		4
Expected return on plan assets (a)	(52)		(52)		(4)		(5)
Amortization of prior service credit (a)	—		(1)		—		(1)
Amortization of net loss (a)	5		18		1		—

Net periodic benefit cost (credit)	11		18		2		(1)
Effects of regulation	7		1		—		—
Net benefit cost (credit) recognized for financial reporting	$	18	$	19	$	2	$	(1)


	Six Months Ended June 30
	2023		2022		2023		2022
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	37	$	49	$	—	$	1
Interest cost (a)	80		55		11		8
Expected return on plan assets (a)	(105)		(104)		(9)		(9)
Amortization of prior service credit (a)	(1)		(1)		—		(3)
Amortization of net loss (a)	11		37		1		1
Settlement charge (b)	—		(1)		—		—
Net periodic benefit cost (credit)	22		35		3		(2)
Effects of regulation	14		6		—		1
Net benefit cost (credit) recognized for financial reporting	$	36	$	41	$	3	$	(1)

(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 six months ended June 30, 2022, Xcel Energy recognized $1 million in settlement charge true-ups related to the fourth quarter of 2021.

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


10. Commitments and Contingencies

Legal

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

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

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

One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected later this year. 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. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million.

Also in February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. PSCo continues to believe CORE's claims are without merit and disputes CORE’s right to withdraw. The Denver District Court trial is scheduled to begin in October 2023.

Marshall Wildfire

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.

As of July 24, 2023, PSCo is aware of approximately 8 complaints on behalf of at least 586 plaintiffs relating to the Marshall Fire and expects that it may receive further complaints. 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, and inverse condemnation.

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.

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 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 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.

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.

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. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the fuel clause adjustment.

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

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

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 June 2023, NSP-Minnesota and the DOC filed direct testimony. The DOC changed its recommendation to a refund of either $58 million or $72 million based on methodologies that do not account for prior disallowances or other amounts returned to customers plus interest. No other party filed direct testimony. A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote.

MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership).The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.

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

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

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

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

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

Environmental

MGP, Landfill and Disposal Sites

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

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

Environmental Requirements — Water and Waste

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

As of June 30, 2023, Xcel Energy had eight regulated ash units in operation.

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.

Investigation and feasibility studies for additional corrective action related to offsite groundwater are ongoing (at three Colorado sites). While the results are uncertain, additional costs are estimated to be at least $40 million. A liability has been recorded and is expected to be fully recoverable through regulatory mechanisms.

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

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

Monticello Tritium — Monticello regularly monitors onsite tritium levels (a weak radioactive isotope that is a byproduct of plant operations) from releases in groundwater monitoring wells onsite. In late 2022, Xcel Energy detected a release of tritium to groundwater and reported the event to the NRC and the State of Minnesota. Xcel Energy has completed repairs, replaced the source of the release and is in the process of mitigating the impact to groundwater, while continuing to monitor onsite wells and evaluating potential future actions for additional containment. The release does not represent a risk to human health or the environment.

Environmental Requirements — Air

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

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

SPS and NSP-Minnesota have joined other impacted 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 and not applicable to SPS and NSP-Minnesota until litigation concludes.

Regional Haze Rules — In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule. In July 2023, the EPA issued a prepublication proposed rule to address the first planning period for the Clean Air Act regional haze reasonable further progress requirements in Texas. As proposed, no additional controls are required at SPS generating facilities.

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

The EPA has proposed to require installation of SO2 controls as BART rather than participation in the trading program. For Harrington Units 1 and 2, EPA has alternatively proposed that Harrington may comply with the SO2 control requirements by agreeing to include the planned January 1, 2025 gas conversion in the federal plan.

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 June 30
(Millions of Dollars)	2023		2022
Operating leases
PPA capacity payments	$	61	$	60
Other operating leases (a)	12		9
Total operating lease expense (b)	$	73	$	69
Finance leases
Amortization of ROU assets	$	—	$	1
Interest expense on lease liability	4		4
Total finance lease expense	$	4	$	5

(a)Includes short-term lease expense of $3 million and $2 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.


	Six Months Ended June 30
(Millions of Dollars)	2023		2022
Operating leases
PPA capacity payments	$	121	$	123
Other operating leases (a)	24		20
Total operating lease expense (b)	$	145	$	143
Finance leases
Amortization of ROU assets	$	1	$	2
Interest expense on lease liability	8		8
Total finance lease expense	$	9	$	10

(a)Includes short-term lease expense of $5 million and $3 million for 2023 and 2022, respectively.

Commitments under operating and finance leases as of June 30, 2023:


(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)
Total minimum obligation	$	1,166	$	250	$	1,416	$	222
Interest component of obligation	(150)		(74)		(224)		(158)
Present value of minimum obligation	$	1,016	176		1,192		64
Less current portion					(226)		(2)
Noncurrent operating and finance lease liabilities					$	966	$	62

(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 the IPP.

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 concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had approximately 4,053 MW and 3,961 MW of capacity under long-term PPAs at June 30, 2023 and Dec. 31, 2022, respectively, 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 guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the agreements. Most of the guarantees and bond indemnities issued by Xcel Energy have a stated maximum amount.

As of June 30, 2023 and Dec. 31, 2022, 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 $63 million and $62 million at June 30, 2023 and Dec. 31, 2022, respectively.

Other Indemnification Agreements — Xcel Energy provides 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 obligations under these agreements may be limited in duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated.

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.

Xcel Energy had equity method investments of $240 million and $219 million as of June 30, 2023 and Dec. 31, 2022, respectively, included in the natural gas utility and all other segments.

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

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

Xcel Energy’s segment information:


	Three Months Ended June 30
(Millions of Dollars)	2023		2022
Regulated Electric


Total revenues	$	2,601	$	2,923
Net income	350		337
Regulated Natural Gas
Operating revenues	$	393	$	476
Intersegment revenue	—		1
Total revenues	$	393	$	477
Net (loss) income	(22)		25
All Other
Total revenues	$	28	$	25
Net loss	(40)		(34)
Consolidated Total
Total revenues	$	3,022	$	3,425
Reconciling eliminations	—		(1)
Total operating revenues	$	3,022	$	3,424
Net income	288		328


	Six Months Ended June 30
(Millions of Dollars)	2023		2022
Regulated Electric


Total revenues	$	5,364	$	5,556
Net income	646		615
Regulated Natural Gas
Operating revenues	$	1,681	$	1,566
Intersegment revenue	2		1
Total revenues	$	1,683	$	1,567
Net income	137		155
All Other
Total revenues	$	57	$	53
Net loss	(77)		(62)
Consolidated Total
Total revenues	$	7,104	$	7,176
Reconciling eliminations	(2)		(1)
Total operating revenues	$	7,102	$	7,175
Net income	706		708

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. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the three and six months ended June 30, 2023 and 2022, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

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

Summarized diluted EPS for Xcel Energy:


	Three Months Ended June 30				Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2023		2022		2023		2022
PSCo	$	0.17	$	0.24	$	0.56	$	0.56
NSP-Minnesota	0.23		0.22		0.48		0.45
SPS	0.15		0.17		0.25		0.27
NSP-Wisconsin	0.05		0.03		0.13		0.11
Earnings from equity method investments — WYCO	0.01		0.01		0.02		0.02
Regulated utility (a)	0.60		0.67		1.43		1.41
Xcel Energy Inc. and Other	(0.08)		(0.07)		(0.15)		(0.11)
Total (a)	$	0.52	$	0.60	$	1.28	$	1.30

(a) Amounts may not add due to rounding.

Summary of Earnings

Xcel Energy — Xcel Energy’s second quarter diluted earnings were $0.52 per share in 2023 compared with $0.60 per share in 2022. The decrease was primarily driven by unfavorable weather experienced in Colorado and SPS territories as well as higher O&M and interest charges, without expected increases in regulatory recovery to offset these drivers including the outcome of the Minnesota Electric Rate Case. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

PSCo — Earnings decreased $0.07 per share for the second quarter of 2023 and were flat year-to-date. Year-to-date earnings primarily reflect higher recovery of infrastructure investment (electric and natural gas), offset by increased depreciation, O&M expenses, interest charges and unfavorable weather.

NSP-Minnesota — Earnings increased $0.01 per share for the second quarter of 2023 and $0.03 year-to-date. The year-to-date change was driven by increased electric infrastructure investment (non-fuel riders).

SPS — Earnings decreased $0.02 per share for the second quarter of 2023 and year-to-date. The impact of regulatory rate outcomes and sales growth was more than offset by unfavorable weather, increased depreciation and interest expenses (excluding the impact of the prior year Texas rate case surcharge amounts).

NSP-Wisconsin — Earnings increased $0.02 per share for the second quarter of 2023 and year-to-date. Additional electric and natural gas infrastructure investment recoveries were partially offset by higher depreciation and O&M expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company and earnings from Energy Impact Partners funds equity method investments. Earnings decreased $0.01 per share for the second quarter and $0.04 year-to-date, largely attributable to higher interest charges.

Changes in GAAP and Ongoing Diluted EPS

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


Diluted Earnings (Loss) Per Share	Three Months Ended June 30		Six Months Ended June 30
GAAP and ongoing diluted EPS — 2022	$	0.60	$	1.30

Components of change - 2023 vs. 2022
Lower electric revenues, net of electric fuel and purchased power	(0.23)		(0.09)
Higher O&M expenses	(0.02)		(0.09)
Higher interest charges	(0.03)		(0.08)
Higher natural gas revenues, net of cost of natural gas sold and transported	—		0.08
Lower taxes (other than income taxes)	0.06		0.04
Higher other income (expense)	0.02		0.03
Lower depreciation and amortization	0.10		0.02
Lower effective tax rate (ETR) (a)	—		0.02
Other, net	0.02		0.05
GAAP and ongoing diluted EPS — 2023	$	0.52	$	1.28

(a)Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.

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, decoupling mechanisms in Colorado and sales true-up mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric utility in those jurisdictions.

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

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

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

Percentage increase (decrease) in normal and actual HDD:


	Three Months Ended June 30						Six Months Ended June 30
	2023 vs. Normal		2022 vs. Normal		2023 vs. 2022		2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
HDD	(9.5)	%	6.3	%	(14.5)	%	(0.7)	%	9.1	%	(8.5)	%
CDD	(26.3)		29.7		(42.8)		(27.1)		28.9		(42.8)
THI	44.6		21.3		18.6		44.2		21.0		18.5

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


	Three Months Ended June 30						Six Months Ended June 30
	2023 vs. Normal		2022 vs. Normal		2023 vs. 2022		2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
Retail electric	$	0.001	$	0.028	$	(0.027)	$	0.003	$	0.049	$	(0.046)
Decoupling and sales true-up	(0.017)		(0.013)		(0.004)		(0.023)		(0.023)		—
Electric total	$	(0.016)	$	0.015	$	(0.031)	$	(0.020)	$	0.026	$	(0.046)
Firm natural gas	(0.003)		0.003		(0.006)		0.026		0.019		0.007
Total	$	(0.019)	$	0.018	$	(0.037)	$	0.006	$	0.045	$	(0.039)

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


	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(8.0)	%	3.3	%	(13.1)	%	(1.1)	%	(3.5)	%
Electric C&I	(3.1)		1.3		2.9		1.6		0.5
Total retail electric sales	(4.6)		1.9		0.2		0.9		(0.6)
Firm natural gas sales	3.7		(16.5)		N/A		(11.4)		(4.1)


	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(1.3)	%	0.1	%	(3.1)	%	(1.0)	%	(1.0)	%
Electric C&I	(1.1)		0.7		4.0		1.5		1.2
Total retail electric sales	(1.1)		0.5		2.8		0.9		0.6
Firm natural gas sales	6.0		(3.5)		N/A		(2.0)		2.5



	Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(3.4)	%	(0.6)	%	(7.6)	%	(4.1)	%	(2.9)	%
Electric C&I	(2.1)		(0.2)		5.0		0.8		0.8
Total retail electric sales	(2.5)		(0.4)		2.7		(0.6)		(0.3)
Firm natural gas sales	5.3		(11.6)		N/A		(13.6)		(1.8)



	Six Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(1.1)	%	(0.6)	%	0.3	%	(0.9)	%	(0.7)	%
Electric C&I	(1.3)		(0.3)		5.5		1.1		1.2
Total retail electric sales	(1.2)		(0.4)		4.6		0.5		0.6
Firm natural gas sales	1.5		(1.8)		N/A		(2.1)		0.1

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

•PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.3% increase in customers. The C&I sales decline was related to decreased use per customer, primarily due to the manufacturing and agricultural sectors.

•NSP-Minnesota — Residential sales declined due to decreased use per customer, partially offset by a 1.1% increase in customers.

•SPS — Residential sales growth was primarily attributable to a 0.8% increase in customers, partially offset by decreased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector.

•NSP-Wisconsin — Residential sales declined due to decreased use per customer, offset by a 0.7% increase in customers. C&I sales growth was associated with customer growth, experienced largely in the transportation and professional services sectors.

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

•Natural gas sales reflect a lower use per residential customer in all jurisdictions, partially offset by an increase in C&I use per customer in PSCo. In addition, residential and C&I customer growth was 1.2% and 0.7%, respectively.

Electric Margin

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact due to 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 June 30				Six Months Ended June 30
(Millions of Dollars)	2023		2022		2023		2022
Electric revenues	$	2,601	$	2,923	$	5,364	$	5,556
Electric fuel and purchased power	(1,030)		(1,181)		(2,147)		(2,275)
Electric margin	$	1,571	$	1,742	$	3,217	$	3,281


(Millions of Dollars)	Three Months Ended June 30, 2023 vs. 2022		Six Months Ended June 30, 2023 vs. 2022
Revenue recognition for the Texas rate case surcharge (a)	$	(85)	$	(85)
Conservation and demand side management (offset in expense)	(18)		(35)
Estimated impact of weather (net of decoupling/sales true-up)	(23)		(33)
PTCs flowed back to customers (offset by lower ETR)	(11)		(23)
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, Wisconsin and South Dakota) (b)	(38)		51
Non-fuel riders	13		29
Wholesale transmission (net)	6		23
Sales and demand (c)	(1)		22
Other (net)	(14)		(13)



Total decrease	$	(171)	$	(64)

(a)The decline in electric margin is due to the recognition of the Texas rate case outcome in the second quarter of 2022, which was largely offset by recognition of previously deferred costs.

(b)Decrease primarily relates to the Minnesota Electric Rate Case (approximately $60 million — see Public Utility Regulation). Reduced electric margin was offset by corresponding reductions in depreciation expense, taxes (other than income taxes) and other items.

(c)Sales excludes weather impact, net of partial decoupling in Colorado and sales true-up mechanism in Minnesota.

Natural Gas Margin

Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold 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 and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.

Natural gas revenues, cost of natural gas sold and transported and margin:


	Three Months Ended June 30				Six Months Ended June 30
(Millions of Dollars)	2023		2022		2023		2022
Natural gas revenues	$	393	$	476	$	1,681	$	1,566
Cost of natural gas sold and transported	(170)		(251)		(1,014)		(961)
Natural gas margin	$	223	$	225	$	667	$	605


(Millions of Dollars)	Three Months Ended June 30, 2023 vs. 2022		Six Months Ended June 30, 2023 vs. 2022
Regulatory rate outcomes (Colorado and Wisconsin)	$	1	$	49
Estimated impact of weather	(5)		5

Infrastructure and integrity riders	—		4



Other (net)	2		4
Total (decrease) increase	$	(2)	$	62

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $14 million for the second quarter and $62 million year-to-date. The increase was primarily due to timing of planned generation outages; additional bad debt expenses; higher insurance and the impact of inflationary pressures, including labor increases, partially offset by the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022 (offset in Electric revenues).

Depreciation and Amortization — Depreciation and amortization decreased $73 million for the second quarter and $11 million year-to-date, largely related to the recognition of previously deferred depreciation costs associated with the Texas Electric Rate Case in 2022 (approximately $40 million) and depreciation life extensions implemented in the Minnesota Electric Rate Case ($48 million), partially offset by system expansion.

Taxes (other than Income Taxes) —Taxes (other than income taxes) decreased $42 million for the second quarter and $29 million year-to-date, primarily associated with the $25 million of deferrals related to the Minnesota Electric Rate Case and the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022.

Other Income (Expense) —Other income (expense) increased $17 million for the second quarter and $21 million year-to-date, largely related to rabbi trust performance, which is partially offset in O&M expenses (employee benefit costs).

Interest Charges — Interest charges increased $21 million for the second quarter and $60 million year-to-date, largely due to higher interest rates and increased long-term debt levels, partially offset by the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022.


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 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 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the Minnesota Public Utilities Commission (MPUC). The rate case is based on a requested ROE of 10.2%, a 52.5% equity ratio and forward test years. In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.

In March 2023, the ALJ’s report was issued, which included an estimated rate increase of approximately $386 million over three years from 2022-2024, based on a ROE of 9.87% and an equity ratio of 52.5%.

In July 2023, the MPUC approved a three-year rate increase of approximately $311 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.

NSP-Minnesota plans to file for reconsideration of the decision in August 2023. The MPUC will have 60 days to respond to the reconsideration request.

Modifications to NSP-Minnesota’s request were as follows:


(Millions of Dollars)	2022			2023			2024
NSP-Minnesota’s revised revenue request	$	233		$	328		$	498
Sherco 3 and A.S. King moved to new docket	—			—			(35)
New property tax forecast	—			(11)			(23)
NSP-Minnesota’s revised revenue request at Oral Arguments	233			317			440
Impact of ROE change	(77)			(82)			(85)
Operating & maintenance expenses	(27)			(29)			(32)
Production tax credit forecast update with tracker	(28)			(1)			(1)
Prepaid and accrued pension	(9)			(10)			(11)
Other, net	9			(5)			—
Total proposed revenue change	$	101		$	190		$	311

Annual incremental revenue change	$	101		$	89		$	121
Annual percentage increase	3.1		%	2.7		%	3.7		%

2022 South Dakota Electric Rate Case —In June 2022, NSP-Minnesota filed a South Dakota electric rate case 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, a requested return on equity of 10.75%, rate base of approximately $947 million and an equity ratio of 53%.

In June 2023, SDPUC Staff approved an uncontested settlement agreement. Key terms of the decision include:

•Increase in base rate and infrastructure rider revenue of $14 million.

•Decreases in depreciation expense of $7 million (change in depreciable lives) and nuclear decommissioning expense of $5 million from NSP-Minnesota’s rate request.

•Confidential equity ratio and ROE.

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. In May 2023, NSP-Minnesota filed a recommended portfolio, which proposed an additional 250 MW of self-build solar generation at the site of our retiring Sherco coal units and a 100 MW solar PPA located in Wisconsin as part of the resource plan RFP. A MPUC decision is expected later this year.

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.

In June 2023, NSP-Minnesota filed a request to withdraw its request, which is pending MPUC approval.

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 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, appropriately represent, in all material respects, the current status of nuclear power operations.

NSP-Wisconsin

Pending Regulatory Proceedings

Wisconsin Rate Case — In April 2023, NSP-Wisconsin filed a Wisconsin rate case seeking an electric increase of $40 million (rate increase of 4.8%) and a natural gas increase of $9 million (rate increase of 5.3%). The rate request is based on a ROE of 10.25%, a 52.5% equity ratio and 2024 forward-looking test year. A final decision by the PSCW is expected in late fourth quarter of 2023.

PSCo

Pending and Recently Concluded Regulatory Proceedings

Colorado Electric Rate Case — In November 2022, PSCo filed a Colorado electric rate case seeking a net increase of $262 million, or 8.2%. The total request reflects a $312 million increase (subsequently adjusted to $303 million in rebuttal), which includes $50 million of authorized costs currently recovered through various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion.

PSCo’s request for a 2023 TCA rider revenue requirement of $41 million has also been consolidated with the pending electric rate case.

In June 2023, PSCo, the Staff, Utility Consumer Advocate, Colorado Energy Office, Colorado Energy Consumers and various other intervenors filed a nearly comprehensive settlement. The City of Boulder opposes the settlement. Terms of the settlement include:

•Retail revenue increase (excluding rider roll-ins) of $95 million (increase of 2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments.

•Alternatively, retail revenue increase (excluding rider roll-ins) of $47 million (increase of 1.46%), if depreciation expense deferrals associated with certain coal generating assets are accepted by the CPUC. This adjustment, if approved, would be earnings neutral, but reduce annual cash flow by $47 million.

•Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).

•Early termination of the revenue decoupling pilot with implementation of new rates. PSCo agreed to credit disputed amounts over the 3% soft cap provisions to customers through application against deferred balances.

•Continuation of previously authorized trackers and deferrals.

•Collection of $12 million of 2023 TCA revenues, previously suspended by the CPUC. Intervenors’ recommended adjustments to the TCA, including prudency tests, exclusion of repair or replacement projects and a historic test year, are subject to CPUC review and any changes to the TCA would apply prospectively beginning in 2024.

A CPUC decision is expected in the third quarter of 2023, with rates to be effective in September 2023.

Colorado Resource Plan— In August 2022, the CPUC approved an updated settlement, which will result in 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 recovery for the retiring coal units to a separate docket. In the second quarter of 2023, the CPUC approved a settlement 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.

In December 2022, PSCo commenced the RFP process for generation resources with bids due in March 2023. In March 2023 PSCo filed its 30-Day Report summarizing bids received. In the third quarter of 2023, PSCo will file its 120-Day Report which will propose a “Preferred Plan” of resources to be acquired as well as other sensitivity portfolios requested by the Commission. A CPUC decision on the resources to be acquired is expected in the fourth quarter of 2023.

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.

In the second quarter, PSCo filed to recover the $25 million of ordinary costs from July through December 2023. The remaining $28 million is the subject of a separate proceeding and is expected to be recovered no later than the first quarter of 2024.

GCA Reform — In 2021, the CPUC issued a NOPR to address the recovery of costs through the GCA. The CPUC and stakeholders worked on gas rules in 2021 and 2022, requiring each LDC to bring forward its own PIM in a future filing. In June 2023, PSCo received approval of a waiver to not file such a PIM until the CPUC can review forthcoming gas cost recovery filings and rulemaking in response to the below legislation recently enacted in Colorado.

In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines). This legislation will require additional rulemaking from the CPUC prior to implementation. In particular, the legislation calls for gas utilities to file a gas price risk management plan by Nov. 1, 2023. In addition, the legislation calls for the CPUC to adopt rules by Jan. 1, 2025 to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers.

SPS

Pending and Recently Concluded Regulatory Proceedings

2022 New Mexico Electric Rate Case — In November 2022, SPS filed a New Mexico electric rate case seeking a revenue increase of $78 million, or 10%. In May 2023, SPS revised its request to $75 million. The request is based on a ROE of 10.75%, an equity ratio of 54.7%, a future test year ending June 30, 2024, rate base of $2.4 billion and acceleration of the Tolk coal plant depreciation life from 2032 to 2028.

In May 2023, SPS, Staff, and various parties filed a contested comprehensive stipulation. Two environmental advocacy organizations, opposed the stipulation. However, one intervenor withdrew their opposition and abstained. Hearings were held in June 2023.

Terms of the contested stipulation include:

•Base rate revenue increase of $33 million, based on the filed future test year.

•ROE of 9.5%.

•Equity ratio of 54.7%.

•Acceleration of Tolk coal plant depreciation life to 2028.

A NMPRC decision is anticipated in the fourth quarter of 2023.

2023 Texas Electric Rate Case — In February 2023, SPS filed a Texas electric rate case seeking an increase in base rate revenue of $149 million (13%). In March 2023, SPS updated the filing, which increased the rate revenue request to $158 million (14% impact to customer bills). The request is based on a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the request reflects the acceleration of the Tolk coal plant depreciation life from 2034 to 2028. SPS is requesting a surcharge from July 13, 2023 through the effective date of new base rates.

Next steps in the procedural schedule are as follows:

•Intervenor direct testimony: August 4, 2023.

•Staff direct testimony: August 11, 2023.

•Rebuttal testimony: August 25, 2023.

•Hearings: Sept. 12-21, 2023.

•Proposed findings: Oct. 25, 2023.

A PUCT decision 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.

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

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 there have been improvements in the 2023 deployment plan, the supply chain challenges persist. As a result of delays, Xcel Energy projects impacts to deployment schedules into 2025.

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, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential 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 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., as a result of implementation of the Uyghur Forced Labor Protection Act) or disruptions in solar imports from key suppliers could impact project timelines and costs.


Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. The financial and operating environment also may have a significant effect on the operation of the business and results reported. Items considered critical, in addition to the matter noted below, are included within the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2022.

Loss Contingencies – Marshall Fire

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

Environmental

Clean Air Act

Power Plant Greenhouse Gas Regulations— In May 2023, the EPA published proposed rules addressing control of CO2 emissions from the power sector. The rule proposed regulations for new natural gas generating units under Clean Air Act Section 111(b) and emission guidelines for existing coal and certain natural gas generation under Clean Air Action Section 111(d). The proposed rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO2 control requirements vary by subcategory. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

Coal Ash Regulation

In May 2023, the EPA published proposed rules to regulate legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at regulated CCR facilities under the CCR Rule for the first time. The proposed rule would subject these areas to the CCR Rule requirements, including groundwater monitoring, corrective action, closure, and post-closure care requirements, among other requirements, with several of the deadlines accelerated.

The EPA has committed to a May 2024 effective date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2023 that further expand the scope of the CCR Rule. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives would be recoverable through rates based on prior state commission practices.

Emerging Contaminants of Concern

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

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.

Xcel Energy provided comments related to both efforts described above through its regulatory coalitions. Final rules are expected in 2024. Costs are uncertain until a final rule is published.

The proposed rules could result in new obligations for investigation and cleanup. Xcel Energy is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.

Effluent Limitation Guidelines

In March 2023, the EPA released a proposed rule 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 to the proposed regulations were submitted on May 30, 2023. The impact of these proposed regulations is uncertain until a final rule is published.


Derivatives, Risk Management and Market Risk

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

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

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

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

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

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

Fair value of net commodity trading contracts as of June 30, 2023:


	Futures / Forwards Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	$	(3)	$	(3)	$	(4)	$	—	$	(10)
NSP- Minnesota (b)	1		(7)		(3)		(2)		(11)
PSCo (a)	4		1		2		—		7
PSCo (b)	(32)		4		2		—		(26)
	$	(30)	$	(5)	$	(3)	$	(2)	$	(40)


	Options Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	$	—	$	—	$	4	$	11	$	15
PSCo (b)	25		—		—		—		25
	$	25	$	—	$	4	$	11	$	40

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

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

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the six months ended June 30:


(Millions of Dollars)	2023		2022
Fair value of commodity trading net contracts outstanding at Jan. 1	$	(33)	$	(33)
Contracts realized or settled during the period	—		6
Commodity trading contract additions and changes during the period	33		19
Fair value of commodity trading net contracts outstanding at June 30	$	—	$	(8)

A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $5 million at June 30, 2023, and approximately $13 million at June 30, 2022. Market price movements can exceed 10% under abnormal circumstances.

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

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


(Millions of Dollars)	Three Months Ended June 30		Average		High		Low
2023	$	0.5	$	0.5	$	0.7	$	0.3
2022	1.8		2.0		3.3		1.1

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 is scheduled to take delivery of approximately 26% of its average enriched nuclear material requirements from Russia through 2030. Given the evolving situation in Ukraine and its global impacts, NSP-Minnesota has entered into additional new contracts that cover potential supply interruptions of nuclear material from Russia.

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 $5 million and $2 million in June 30, 2023 and 2022, respectively.

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

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

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

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

At June 30, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $47 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $46 million. At June 30, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $86 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $73 million.

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

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


Fair Value Measurements

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 8 and 9 to the consolidated financial statements for further information.


Liquidity and Capital Resources

Cash Flows

Operating Cash Flows


(Millions of Dollars)	Six Months Ended June 30
Cash provided by operating activities — 2022	$	1,988

Components of change — 2023 vs. 2022
Lower net income	(2)
Non-cash transactions	(69)
Changes in working capital	253
Changes in net regulatory and other assets and liabilities	285
Cash provided by operating activities — 2023	$	2,455

Net cash provided by operating activities increased $467 million for the six months ended June 30, 2023 compared with the prior year. The increase was primarily due to the impact of decreasing natural gas prices on customer receivables and accounts payable, as well as continued collections of deferred net natural gas, fuel and purchased energy costs.

Investing Cash Flows


(Millions of Dollars)	Six Months Ended June 30
Cash used in investing activities — 2022	$	(2,055)

Components of change — 2023 vs. 2022
Increased capital expenditures	(559)
Other investing activities	(25)
Cash used in investing activities — 2023	$	(2,639)

Net cash used in investing activities increased $584 million for the six months ended June 30, 2023 compared with the prior year. The increase in capital expenditures was largely due to continued system expansion.

Financing Cash Flows


(Millions of Dollars)	Six Months Ended June 30
Cash provided by financing activities — 2022	$	236

Components of change — 2023 vs. 2022
Lower net short-term repayments	600
Lower net long-term debt proceeds	(375)
Lower proceeds from issuance of common stock	(76)

Other financing activities	(37)
Cash provided by financing activities — 2023	$	348

Net cash provided by financing activities increased $112 million for the six months ended June 30, 2023 compared with the prior year. The increase was largely related to the amount/timing of debt issuances and repayments.

Capital Requirements

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

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

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

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

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

Capital Sources

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

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

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

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


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,500	$	368	$	1,132	$	2	$	1,134
PSCo	700		29		671		2		673
NSP-Minnesota	700		15		685		7		692
SPS	500		96		404		1		405
NSP-Wisconsin	150		—		150		3		153
Total	$	3,550	$	508	$	3,042	$	15	$	3,057

(a)Credit facilities expire in September 2027.

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

Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of June 30, 2023, 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 Planned Financing Activity— During 2023, Xcel Energy plans to issue approximately $85 million of equity through the DRIP and benefit programs. In addition, we issued approximately $62 million of equity under the ATM program in the first half of 2023. Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:

Issuer

Security

Amount

Status

Tenor

Coupon

PSCo

First Mortgage Bonds

850

million

Completed

30 Year

5.25%

NSP-Wisconsin

First Mortgage Bonds

125

million

Completed

30 Year

5.30

NSP-Minnesota

First Mortgage Bonds

800

million

Completed

30 Year

5.10

Xcel Energy

Unsecured Senior Notes

700

million

Third Quarter

N/A

SPS

First Mortgage Bonds

100

million

Third Quarter

N/A

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 and other factors.

Off-Balance-Sheet Arrangements

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

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

Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)

Key assumptions as compared with 2022 levels unless noted:

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

•Normal weather patterns for the remainder of the year.

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

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

•Capital rider revenue is projected to increase $40 million to $50 million (net of PTCs). The change from the previous estimate is largely due to a change in the projected levels of PTCs driven by a change in the PTC rate, which are offset in the ETR and largely earnings neutral.

•O&M expenses are projected to decline ~3%.

•Depreciation expense is projected to increase approximately $30 million to $40 million. The change from the previous estimate is largely due to longer depreciation lives approved in the Minnesota Electric Rate Case and other regulatory decisions, which are generally offset by lower revenue.

•Property taxes are projected to decrease $20 million to $30 million. The change from the previous estimate is largely due to regulatory decisions, which are generally offset by lower revenue.

•Interest expense (net of AFUDC - debt) is projected to increase $80 million to $90 million. The change from the previous estimate is largely due to regulatory decisions (generally offset by lower revenue) and lower than projected interest rates on recent bond issuances.

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

•ETR is projected to be ~(9%) to (11%). The change from the previous estimate is largely due to a change in the projected levels of PTCs and a change in the PTC rate, which are offset in the capital riders and fuel mechanisms and are largely earnings neutral.

(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. Xcel Energy is unable to forecast if any of these items will occur or 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 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $3.20 per share.

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

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

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


ITEM 3 — QUANTITATIVE ANDQUALITATIVE 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 under “Derivatives, Risk Management and Market Risk.”


ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

As of June 30, 2023, 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, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.


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

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:

For the quarter endedJune 30, 2023, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.


ITEM 5 — OTHER INFORMATION

None of the Company’s directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended June 30, 2023.


Class						Outstanding at July 25, 2023
Common Stock, $2.50 par value						551,532,742 shares


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	5
	Consolidated Statements of Income	5
	Consolidated Statements of Comprehensive Income	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Common Stockholders’ Equity	9
	Notes to Consolidated Financial Statements	10
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	33
Item 4 —	Controls and Procedures	33

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	33
Item 1A —	Risk Factors	33
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 5 —	Other Information	33
Item 6 —	Exhibits	34

SIGNATURES		35


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


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


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


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


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 on April 3, 2020	Xcel Energy Inc Form 8-K dated April 3, 2020	3.01
4.01*	Supplemental Trust Indenture dated as of May 1, 2023 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $800 million aggregate principal amount of 5.10% First Mortgage Bonds, Series due May 15, 2053	NSP-Minnesota Form 8-K dated May 8, 2023	4.01
4.02*	Supplemental Indenture dated as of May 10, 2023 between NSP-Wisconsin and U.S. Bank Trust Company, National Association, as successor Trustee, creating 5.30% First Mortgage Bonds, Series due June 15, 2053	NSP-Wisconsin Form 8-K dated May 10, 2023	4.01
10.01	Summary of Non-Employee Director Compensation, effective as of May 24, 2023
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.01	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


		XCEL ENERGY INC.

7/27/2023	By:	/s/ BRIAN J. VAN ABEL
		Brian J. Van Abel
		Executive Vice President, Chief Financial Officer
		(Principal Accounting Officer and Principal Financial Officer)


Forward-Looking Statements