UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended Sept. 30, ~~2022~~2023


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

For the transition period from to

Commission File Number: 001-3034


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

Minnesota

41-0448030

(State or Other Jurisdiction of Incorporation or Organization)

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

414 Nicollet Mall

Minneapolis

Minnesota

55401

(Address of Principal Executive Offices)

(Zip Code)


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


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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $2.50 par value

XEL

Nasdaq Stock Market LLC

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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


Class						Outstanding at ~~Oct. 25, 2022~~October 24, 2023
Common Stock, $2.50 par value						~~547,248,496~~551,816,319 shares

TABLE OF CONTENTS


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	5
	Consolidated Statements of Income	5
	Consolidated Statements of Comprehensive Income	6
	Consolidated Statements of Cash Flows	7
	Consolidated Balance Sheets	8
	Consolidated Statements of Common Stockholders’ Equity	9
	Notes to Consolidated Financial Statements	10
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2122
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	3334
Item 4 —	Controls and Procedures	3334

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	3334
Item 1A —	Risk Factors	34
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 5 —	Other Information	34
Item 6 —	Exhibits	3435

SIGNATURES		3536

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

Definitions of Abbreviations


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


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


MPUC			Minnesota Public Utilities Commission

~~NDPSC~~NMPRC			~~North Dakota~~New Mexico Public ~~Service~~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
~~GCA~~ECA			~~Gas cost~~Retail electric commodity adjustment
~~GUIC~~			~~Gas utility infrastructure cost rider~~
~~RES~~			~~Renewable energy standard~~
~~TCR~~			~~Transmission cost recovery adjustment~~


Other
AFUDC			Allowance for funds used during construction

ALJ			Administrative Law Judge
~~AMT~~			~~Alternative minimum tax~~
ATM			At-the-market

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


CDD			Cooling degree-days
CEO			Chief executive officer
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFO			Chief financial officer


CORE			CORE Electric Cooperative
~~CPCN~~			~~Certificate of Public Convenience and Necessity~~
CSPV			Crystalline Silicon Photovoltaic
~~CUB~~			~~Citizens Utility Board~~
DRIP			Dividend Reinvestment and Stock Purchase Program
EPS			Earnings per share
ETR			Effective tax rate
FTR			Financial transmission right

GAAP			United States generally accepted accounting principles
GE			General Electric Company
HDD			Heating degree-days
IPP			Independent power producing entity
~~IRA~~IRP			~~Inflation Reduction Act~~Integrated Resource Plan
~~ITC~~JTIQ			~~Investment Tax Credit~~Joint Target Interconnection Queue
~~JSC~~			~~Just Solar Coalition~~
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 ~~PolyFluroroAlkyl~~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
UCA			Colorado Office of the Utility Consumer Advocate
VaR			Value at Risk
~~WACC~~			~~Weighted average cost of capital~~
~~XLI~~			~~Xcel Large Industrial Customers~~


Measurements
MW			Megawatts


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to ~~2022~~2023 and ~~2023~~2024 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2021~~2022 and subsequent filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee ~~work force~~workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of terrorism; ~~cyber security~~cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other ~~weather;~~weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory ~~penalties;~~penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.

Table of Contents

PART I — FINANCIAL INFORMATION


ITEM 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in millions, except per share data)


		Three Months Ended Sept. 30				Nine Months Ended Sept. 30					Three Months Ended Sept. 30				Nine Months Ended Sept. 30
		2022		2021		2022		2021			2023		2022		2023		2022
Operating revenues	Operating revenues									Operating revenues
Electric	Electric	$	3,699	$	3,176	$	9,255	$	8,643	Electric	$	3,387	$	3,699	$	8,751	$	9,255
Natural gas	Natural gas	357		268		1,923		1,364		Natural gas	245		357		1,926		1,923
Other	Other	26		23		79		69		Other	30		26		87		79
Total operating revenues	Total operating revenues	4,082		3,467		11,257		10,076		Total operating revenues	3,662		4,082		10,764		11,257

Operating expenses	Operating expenses									Operating expenses
Electric fuel and purchased power	Electric fuel and purchased power	1,497		1,210		3,772		3,643		Electric fuel and purchased power	1,181		1,497		3,328		3,772
Cost of natural gas sold and transported	Cost of natural gas sold and transported	173		86		1,134		603		Cost of natural gas sold and transported	70		173		1,084		1,134
Cost of sales — other	Cost of sales — other	11		11		32		28		Cost of sales — other	14		11		37		32
O&M expenses		611		568		1,827		1,752
Operating and maintenance expenses										Operating and maintenance expenses	586		611		1,864		1,827
Conservation and demand side management expenses	Conservation and demand side management expenses	86		78		259		222		Conservation and demand side management expenses	76		86		215		259
Depreciation and amortization	Depreciation and amortization	607		537		1,807		1,586		Depreciation and amortization	618		607		1,807		1,807
Taxes (other than income taxes)	Taxes (other than income taxes)	173		152		523		472		Taxes (other than income taxes)	168		173		489		523
Loss on Comanche Unit 3 litigation										Loss on Comanche Unit 3 litigation	34		—		34		—
Total operating expenses	Total operating expenses	3,158		2,642		9,354		8,306		Total operating expenses	2,747		3,158		8,858		9,354

Operating income	Operating income	924		825		1,903		1,770		Operating income	915		924		1,906		1,903

Other (expense) income, net		(15)		(3)		(20)		5
Other income (expense), net										Other income (expense), net	3		(15)		19		(20)
Earnings from equity method investments	Earnings from equity method investments	1		13		27		47		Earnings from equity method investments	7		1		27		27
Allowance for funds used during construction — equity	Allowance for funds used during construction — equity	20		21		53		53		Allowance for funds used during construction — equity	26		20		63		53

Interest charges and financing costs	Interest charges and financing costs									Interest charges and financing costs
Interest charges — includes other financing costs of $8, $7, $24 and $22, respectively		244		211		705		628
Interest charges — includes other financing costs of $8, $8, $24 and $24, respectively										Interest charges — includes other financing costs of $8, $8, $24 and $24, respectively	269		244		790		705
Allowance for funds used during construction — debt	Allowance for funds used during construction — debt	(7)		(7)		(19)		(18)		Allowance for funds used during construction — debt	(14)		(7)		(36)		(19)
Total interest charges and financing costs	Total interest charges and financing costs	237		204		686		610		Total interest charges and financing costs	255		237		754		686

Income before income taxes	Income before income taxes	693		652		1,277		1,265		Income before income taxes	696		693		1,261		1,277
Income tax expense (benefit)	Income tax expense (benefit)	44		43		(80)		(17)		Income tax expense (benefit)	40		44		(101)		(80)
Net income	Net income	$	649	$	609	$	1,357	$	1,282	Net income	$	656	$	649	$	1,362	$	1,357

Weighted average common shares outstanding:	Weighted average common shares outstanding:									Weighted average common shares outstanding:
Basic	Basic	548		539		546		539		Basic	552		548		551		546
Diluted	Diluted	548		539		546		539		Diluted	552		548		552		546

Earnings per average common share:	Earnings per average common share:									Earnings per average common share:
Basic	Basic	$	1.19	$	1.13	$	2.48	$	2.38	Basic	$	1.19	$	1.19	$	2.47	$	2.48
Diluted	Diluted	1.18		1.13		2.48		2.38		Diluted	1.19		1.18		2.47		2.48

See Notes to Consolidated Financial Statements	See Notes to Consolidated Financial Statements									See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in millions)


		Three Months Ended Sept. 30				Nine Months Ended Sept. 30					Three Months Ended Sept. 30				Nine Months Ended Sept. 30
		2022		2021		2022		2021			2023		2022		2023		2022
Net income	Net income	$	649	$	609	$	1,357	$	1,282	Net income	$	656	$	649	$	1,362	$	1,357
Other comprehensive income	Other comprehensive income									Other comprehensive income
Pension and retiree medical benefits:	Pension and retiree medical benefits:									Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $4, $—, $4 and $—, respectively		10		—		11		—
Reclassifications of loss to net income, net of tax of $—, $1, $1 and $2, respectively		1		4		2		5
Net pension and retiree medical losses arising during the period, net of tax of $—, $4, $— and $4, respectively										Net pension and retiree medical losses arising during the period, net of tax of $—, $4, $— and $4, respectively	—		10		—		11
Reclassifications of loss to net income, net of tax of $—, $—, $— and $1, respectively										Reclassifications of loss to net income, net of tax of $—, $—, $— and $1, respectively	—		1		1		2
Derivative instruments:	Derivative instruments:									Derivative instruments:
Net fair value increase, net of tax of $—, $1, $6 and $1, respectively		—		3		15		4
Net fair value increase, net of tax of $1, $—, $4 and $6, respectively										Net fair value increase, net of tax of $1, $—, $4 and $6, respectively	3		—		11		15
Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively	Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively	1		2		4		6		Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively	1		1		3		4

Total other comprehensive income	Total other comprehensive income	12		9		32		15		Total other comprehensive income	4		12		15		32
Total comprehensive income	Total comprehensive income	$	661	$	618	$	1,389	$	1,297	Total comprehensive income	$	660	$	661	$	1,377	$	1,389

See Notes to Consolidated Financial Statements	See Notes to Consolidated Financial Statements									See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in millions)


		Nine Months Ended Sept. 30					Nine Months Ended Sept. 30
		2022		2021			2023		2022
Operating activities	Operating activities					Operating activities
Net income	Net income	$	1,357	$	1,282	Net income	$	1,362	$	1,357
Adjustments to reconcile net income to cash provided by operating activities:	Adjustments to reconcile net income to cash provided by operating activities:					Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	1,821		1,597		Depreciation and amortization	1,824		1,821
Nuclear fuel amortization	Nuclear fuel amortization	91		86		Nuclear fuel amortization	84		91
Deferred income taxes	Deferred income taxes	(85)		(9)		Deferred income taxes	(173)		(85)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(53)		(53)		Allowance for equity funds used during construction	(63)		(53)
Earnings from equity method investments	Earnings from equity method investments	(27)		(47)		Earnings from equity method investments	(27)		(27)
Dividends from equity method investments	Dividends from equity method investments	30		31		Dividends from equity method investments	26		30
Provision for bad debts	Provision for bad debts	41		53		Provision for bad debts	58		41
Share-based compensation expense	Share-based compensation expense	19		20		Share-based compensation expense	17		19
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	(221)		(152)		Accounts receivable	95		(221)
Accrued unbilled revenues	Accrued unbilled revenues	69		58		Accrued unbilled revenues	375		69
Inventories	Inventories	(272)		(82)		Inventories	73		(272)
Other current assets	Other current assets	13		8		Other current assets	104		13
Accounts payable	Accounts payable	152		61		Accounts payable	(226)		152
Net regulatory assets and liabilities	Net regulatory assets and liabilities	239		(997)		Net regulatory assets and liabilities	771		239
Other current liabilities	Other current liabilities	51		(22)		Other current liabilities	183		51
Pension and other employee benefit obligations	Pension and other employee benefit obligations	(59)		(131)		Pension and other employee benefit obligations	(35)		(59)
Other, net	Other, net	1		(124)		Other, net	(95)		1
Net cash provided by operating activities	Net cash provided by operating activities	3,167		1,579		Net cash provided by operating activities	4,353		3,167

Investing activities	Investing activities					Investing activities
Capital/construction expenditures	Capital/construction expenditures	(3,325)		(3,032)		Capital/construction expenditures	(4,240)		(3,325)
Purchase of investment securities	Purchase of investment securities	(1,055)		(540)		Purchase of investment securities	(704)		(1,055)
Proceeds from the sale of investment securities	Proceeds from the sale of investment securities	1,029		531		Proceeds from the sale of investment securities	678		1,029
Other, net	Other, net	30		(24)		Other, net	(26)		30
Net cash used in investing activities	Net cash used in investing activities	(3,321)		(3,065)		Net cash used in investing activities	(4,292)		(3,321)

Financing activities	Financing activities					Financing activities
(Repayments of) proceeds from short-term borrowings, net		(847)		1,163
Repayments of short-term borrowings, net						Repayments of short-term borrowings, net	(813)		(847)
Proceeds from issuances of long-term debt	Proceeds from issuances of long-term debt	2,164		1,920		Proceeds from issuances of long-term debt	2,631		2,164
Repayments of long-term debt, including reacquisition premiums	Repayments of long-term debt, including reacquisition premiums	(600)		(399)		Repayments of long-term debt, including reacquisition premiums	(651)		(600)
Proceeds from issuance of common stock	Proceeds from issuance of common stock	156		13		Proceeds from issuance of common stock	83		156
Dividends paid	Dividends paid	(754)		(698)		Dividends paid	(814)		(754)
Other, net	Other, net	(14)		(11)		Other, net	(14)		(14)
Net cash provided by financing activities	Net cash provided by financing activities	105		1,988		Net cash provided by financing activities	422		105

Net change in cash, cash equivalents and restricted cash	Net change in cash, cash equivalents and restricted cash	(49)		502		Net change in cash, cash equivalents and restricted cash	483		(49)
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	166		129		Cash, cash equivalents and restricted cash at beginning of period	111		166
Cash, cash equivalents and restricted cash at end of period	Cash, cash equivalents and restricted cash at end of period	$	117	$	631	Cash, cash equivalents and restricted cash at end of period	$	594	$	117

Supplemental disclosure of cash flow information:	Supplemental disclosure of cash flow information:					Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	Cash paid for interest (net of amounts capitalized)	$	(628)	$	(592)	Cash paid for interest (net of amounts capitalized)	$	(652)	$	(628)
Cash paid for income taxes, net	Cash paid for income taxes, net	(16)		(6)		Cash paid for income taxes, net	(68)		(16)

Supplemental disclosure of non-cash investing and financing transactions:	Supplemental disclosure of non-cash investing and financing transactions:					Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	Accrued property, plant and equipment additions	$	393	$	476	Accrued property, plant and equipment additions	$	409	$	393
Inventory transfers to property, plant and equipment	Inventory transfers to property, plant and equipment	34		87		Inventory transfers to property, plant and equipment	42		34
Operating lease right-of-use assets	Operating lease right-of-use assets	17		4		Operating lease right-of-use assets	73		17
Allowance for equity funds used during construction	Allowance for equity funds used during construction	53		53		Allowance for equity funds used during construction	63		53
Issuance of common stock for reinvested dividends and/or equity awards	Issuance of common stock for reinvested dividends and/or equity awards	40		26		Issuance of common stock for reinvested dividends and/or equity awards	46		40

See Notes to Consolidated Financial Statements	See Notes to Consolidated Financial Statements					See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

Sept. 30, 2022 Dec. 31, 2021
Assets
Current assets
Cash and cash equivalents $ 117 $ 166
Accounts receivable, net 1,196 1,018
Accrued unbilled revenues 793 862
Inventories 870 631
Regulatory assets 1,275 1,106
Derivative instruments 456 123
Prepaid taxes 54 44
Prepayments and other 329 289
Total current assets 5,090 4,239
Property, plant and equipment, net 47,287 45,457
Other assets
Nuclear decommissioning fund and other investments 3,083 3,628
Regulatory assets 2,850 2,738
Derivative instruments 90 67
Operating lease right-of-use assets 1,155 1,291
Other 420 431
Total other assets 7,598 8,155
Total assets $ 59,975 $ 57,851
Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 651 $ 601
Short-term debt 158 1,005
Accounts payable 1,586 1,409
Regulatory liabilities 596 271
Taxes accrued 545 569
Accrued interest 244 209
Dividends payable 267 249
Derivative instruments 100 69
Operating lease liabilities 211 205
Other 545 459
Total current liabilities 4,903 5,046
Deferred credits and other liabilities
Deferred income taxes 4,762 4,894
Deferred investment tax credits 50 53
Regulatory liabilities 5,567 5,405
Asset retirement obligations 3,296 3,151
Derivative instruments 114 105
Customer advances 187 196
Pension and employee benefit obligations 255 306
Operating lease liabilities 997 1,146
Other 151 158
Total deferred credits and other liabilities 15,379 15,414
Commitments and contingencies
Capitalization
Long-term debt 23,309 21,779
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 547,006,076 and 544,025,269 shares outstanding at Sept. 30, 2022 and Dec. 31, 2021, respectively 1,368 1,360
Additional paid in capital 7,979 7,803
Retained earnings 7,128 6,572
Accumulated other comprehensive loss (91) (123)
Total common stockholders’ equity 16,384 15,612
Total liabilities and equity $ 59,975 $ 57,851
See Notes to Consolidated Financial Statements
data


	Sept. 30, 2023		Dec. 31, 2022
Assets
Current assets
Cash and cash equivalents	$	594	$	111
Accounts receivable, net	1,220		1,373
Accrued unbilled revenues	731		1,105
Inventories	688		803
Regulatory assets	695		1,059
Derivative instruments	146		279
Prepaid taxes	71		54
Prepayments and other	257		360
Total current assets	4,402		5,144

Property, plant and equipment, net	50,613		48,253

Other assets
Nuclear decommissioning fund and other investments	3,393		3,234
Regulatory assets	2,757		2,871
Derivative instruments	72		93
Operating lease right-of-use assets	1,114		1,204
Other	519		389
Total other assets	7,855		7,791
Total assets	$	62,870	$	61,188

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	1,051	$	1,151
Short-term debt	—		813
Accounts payable	1,445		1,804
Regulatory liabilities	462		418
Taxes accrued	541		569
Accrued interest	288		217
Dividends payable	287		268
Derivative instruments	59		76
Operating lease liabilities	231		217
Other	709		545
Total current liabilities	5,073		6,078

Deferred credits and other liabilities
Deferred income taxes	4,702		4,756
Deferred investment tax credits	45		48
Regulatory liabilities	5,809		5,569
Asset retirement obligations	3,332		3,380
Derivative instruments	83		113
Customer advances	173		181
Pension and employee benefit obligations	355		390
Operating lease liabilities	930		1,038
Other	149		147
Total deferred credits and other liabilities	15,578		15,622

Commitments and contingencies
Capitalization
Long-term debt	24,910		22,813
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 551,662,803 and 549,578,018 shares outstanding at Sept. 30, 2023 and December 31, 2022, respectively	1,379		1,374
Additional paid in capital	8,269		8,155
Retained earnings	7,739		7,239
Accumulated other comprehensive loss	(78)		(93)
Total common stockholders’ equity	17,309		16,675
Total liabilities and equity	$	62,870	$	61,188

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

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


		Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss			Total Common Stockholders' Equity			Common Stock Issued							Retained Earnings		Accumulated Other Comprehensive Loss			Total Common Stockholders' Equity
		Shares	Par Value		Additional Paid In Capital						Shares					Par Value		Additional Paid In Capital
Three Months Ended Sept. 30, 2022 and 2021
Balance at June 30, 2021		538,305,927	$	1,346	$	7,435	$	6,146	$	(135)		$	14,792
Net income							609					609
Other comprehensive income									9			9
Dividends declared on common stock ($0.4575 per share)							(247)					(247)
Issuances of common stock		153,025	—		10							10

Share-based compensation					(2)							(2)
Balance at Sept. 30, 2021		538,458,952	$	1,346	$	7,443	$	6,508	$	(126)		$	15,171

Three Months Ended Sept. 30, 2023 and 2022														Three Months Ended Sept. 30, 2023 and 2022
Balance at June 30, 2022	Balance at June 30, 2022	546,807,793	$	1,367	$	7,960	$	6,747	$	(103)		$	15,971	Balance at June 30, 2022	546,807,793		$	1,367	$	7,960		$	6,747	$	(103)		$	15,971
Net income	Net income						649					649		Net income								649					649
Other comprehensive income	Other comprehensive income								12			12		Other comprehensive income										12			12
Dividends declared on common stock ($0.4875 per share)	Dividends declared on common stock ($0.4875 per share)						(267)					(267)		Dividends declared on common stock ($0.4875 per share)								(267)					(267)
Issuances of common stock	Issuances of common stock	198,283	1		13							14		Issuances of common stock	198,283		1		13								14

Share-based compensation	Share-based compensation				6		(1)					5		Share-based compensation					6			(1)					5
Balance at Sept. 30, 2022	Balance at Sept. 30, 2022	547,006,076	$	1,368	$	7,979	$	7,128	$	(91)		$	16,384	Balance at Sept. 30, 2022	547,006,076		$	1,368	$	7,979		$	7,128	$	(91)		$	16,384

Balance at June 30, 2023														Balance at June 30, 2023	551,375,255		$	1,378	$	8,247		$	7,371	$	(82)		$	16,914
Net income														Net income								656					656
Other comprehensive income														Other comprehensive income										4			4
Dividends declared on common stock ($0.52 per share)														Dividends declared on common stock ($0.52 per share)								(287)					(287)
Issuances of common stock														Issuances of common stock	287,548		1		17								18

Share-based compensation														Share-based compensation					5			(1)					4
Balance at Sept. 30, 2023														Balance at Sept. 30, 2023	551,662,803		$	1,379	$	8,269		$	7,739	$	(78)		$	17,309
		Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss			Total Common Stockholders' Equity
		Shares	Par Value		Additional Paid In Capital						Common Stock Issued								Retained Earnings			Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
Nine Months Ended Sept. 30, 2022 and 2021
Balance at Dec. 31, 2020		537,438,394	$	1,344	$	7,404	$	5,968	$	(141)		$	14,575
															Shares		Par Value				Additional Paid In Capital					Retained Earnings			Accumulated Other Comprehensive Loss	Total Common Stockholders' Equity
Nine Months Ended Sept. 30, 2023 and 2022														Nine Months Ended Sept. 30, 2023 and 2022
Balance at Dec. 31, 2021														Balance at Dec. 31, 2021	544,025,269		$	1,360	$	7,803		$	6,572	$	(123)		$	15,612
Net income	Net income						1,282					1,282		Net income								1,357					1,357
Other comprehensive loss									15			15
Dividends declared on common stock ($1.373 per share)							(739)					(739)
Other comprehensive income														Other comprehensive income										32			32
Dividends declared on common stock ($1.4625 per share)														Dividends declared on common stock ($1.4625 per share)								(798)					(798)
Issuances of common stock	Issuances of common stock	1,020,558	2		38							40		Issuances of common stock	2,980,807		8		177								185

Share-based compensation	Share-based compensation				1		(3)					(2)		Share-based compensation					(1)			(3)					(4)

Balance at Sept. 30, 2021		538,458,952	$	1,346	$	7,443	$	6,508	$	(126)		$	15,171
Balance at Sept. 30, 2022														Balance at Sept. 30, 2022	547,006,076		$	1,368	$	7,979		$	7,128	$	(91)		$	16,384

Balance at Dec. 31, 2021		544,025,269	$	1,360	$	7,803	$	6,572	$	(123)		$	15,612
Balance at Dec. 31, 2022														Balance at Dec. 31, 2022	549,578,018		$	1,374	$	8,155		$	7,239	$	(93)		$	16,675
Net income	Net income						1,357					1,357		Net income								1,362					1,362
Other comprehensive income	Other comprehensive income								32			32		Other comprehensive income										15			15
Dividends declared on common stock ($1.463 per share)							(798)					(798)
Dividends declared on common stock ($1.56 per share)														Dividends declared on common stock ($1.56 per share)								(859)					(859)
Issuances of common stock	Issuances of common stock	2,980,807	8		177							185		Issuances of common stock	2,084,785		5		108								113

Share-based compensation	Share-based compensation				(1)		(3)					(4)		Share-based compensation					6			(3)					3
Balance at Sept. 30, 2022		547,006,076	$	1,368	$	7,979	$	7,128	$	(91)		$	16,384
Balance at Sept. 30, 2023														Balance at Sept. 30, 2023	551,662,803		$	1,379	$	8,269		$	7,739	$	(78)		$	17,309

See Notes to Consolidated Financial Statements	See Notes to Consolidated Financial Statements													See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

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 Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021;~~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 nine months ended Sept. 30, ~~2022~~2023 and ~~2021;~~2022; and Xcel Energy’s cash flows for the nine months ended Sept. 30, ~~2022~~2023 and ~~2021.~~2022.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, ~~2022,~~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, ~~2021~~2022 balance sheet information has been derived from the audited ~~2021~~2022 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2021.~~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, ~~2021,~~2022, filed with the SEC on Feb. 23, ~~2022.~~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, ~~2021~~2022 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

As of Sept. 30, ~~2022,~~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)	(Millions of Dollars)	Sept. 30, 2022		Dec. 31, 2021		(Millions of Dollars)	Sept. 30, 2023		Dec. 31, 2022
Accounts receivable, net	Accounts receivable, net					Accounts receivable, net
Accounts receivable	Accounts receivable	$	1,308	$	1,124	Accounts receivable	$	1,347	$	1,495
Less allowance for bad debts	Less allowance for bad debts	(112)		(106)		Less allowance for bad debts	(127)		(122)
Accounts receivable, net	Accounts receivable, net	$	1,196	$	1,018	Accounts receivable, net	$	1,220	$	1,373


(Millions of Dollars)	(Millions of Dollars)	Sept. 30, 2022		Dec. 31, 2021		(Millions of Dollars)	Sept. 30, 2023		Dec. 31, 2022
Inventories	Inventories					Inventories
Materials and supplies	Materials and supplies	$	321	$	289	Materials and supplies	$	368	$	330
Fuel	Fuel	234		182		Fuel	193		201
Natural gas	Natural gas	315		160		Natural gas	127		272
Total inventories	Total inventories	$	870	$	631	Total inventories	$	688	$	803


(Millions of Dollars)	(Millions of Dollars)	Sept. 30, 2022		Dec. 31, 2021		(Millions of Dollars)	Sept. 30, 2023		Dec. 31, 2022
Property, plant and equipment, net	Property, plant and equipment, net					Property, plant and equipment, net
Electric plant	Electric plant	$	48,959	$	48,680	Electric plant	$	51,377	$	49,639
Natural gas plant	Natural gas plant	8,199		7,758		Natural gas plant	9,005		8,514
Common and other property	Common and other property	2,824		2,602		Common and other property	3,227		2,970
Plant to be retired (a)	Plant to be retired (a)	2,258		1,200		Plant to be retired (a)	2,109		2,217
Construction work in progress	Construction work in progress	2,445		1,969		Construction work in progress	2,951		2,124
Total property, plant and equipment	Total property, plant and equipment	64,685		62,209		Total property, plant and equipment	68,669		65,464
Less accumulated depreciation	Less accumulated depreciation	(17,639)		(17,060)		Less accumulated depreciation	(18,363)		(17,502)
Nuclear fuel	Nuclear fuel	3,105		3,081		Nuclear fuel	3,282		3,183
Less accumulated amortization	Less accumulated amortization	(2,864)		(2,773)		Less accumulated amortization	(2,975)		(2,892)
Property, plant and equipment, net	Property, plant and equipment, net	$	47,287	$	45,457	Property, plant and equipment, net	$	50,613	$	48,253

(a)Amounts ~~as of Dec. 31, 2021~~ include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche ~~Unit~~Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and ~~Craig Units 1 and 2~~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. Following the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Sept. 30, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion. 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)	(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2022			Year Ended Dec. 31, 2021			(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2023			Year Ended Dec. 31, 2022
Borrowing limit	Borrowing limit	$	3,550		$	3,100		Borrowing limit	$	3,550		$	3,550
Amount outstanding at period end	Amount outstanding at period end	158			1,005			Amount outstanding at period end	—			813
Average amount outstanding	Average amount outstanding	187			1,399			Average amount outstanding	190			552
Maximum amount outstanding	Maximum amount outstanding	329			2,054			Maximum amount outstanding	613			1,357
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	2.51		%	0.57		%	Weighted average interest rate, computed on a daily basis	5.35		%	1.47		%
Weighted average interest rate at period end	Weighted average interest rate at period end	3.40			0.31			Weighted average interest rate at period end	N/A			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 ~~$39~~were $46 million and ~~$19~~$43 million of letters of credit outstanding under the cr~~edit~~credit facilities at both Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021, respectively.~~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 ~~at least~~ equal to or greater than the ~~amount of~~ 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.

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

•~~Maturities were extended from June 2024 to September 2027.~~

•~~Borrowing limit for Xcel Energy Inc. was increased from $1.25 billion to $1.5 billion.~~

•~~Borrowing limit for NSP-Minnesota was increased from $500 million to $700 million.~~

As of Sept. 30, ~~2022,~~2023, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	Xcel Energy Inc.	$	1,500	$	158	$	1,342	Xcel Energy Inc.	$	1,500	$	—	$	1,500
PSCo	PSCo	700		26		674		PSCo	700		29		671
NSP-Minnesota	NSP-Minnesota	700		11		689		NSP-Minnesota	700		15		685
SPS	SPS	500		2		498		SPS	500		2		498
NSP-Wisconsin	NSP-Wisconsin	150		—		150		NSP-Wisconsin	150		—		150
Total	Total	$	3,550	$	197	$	3,353	Total	$	3,550	$	46	$	3,504

(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 Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021.~~2022.

Bilateral Credit Agreement

In April ~~2022,~~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 Sept. 30, ~~2022,~~2023, NSP-Minnesota had ~~$50~~$56 million of outstanding letters of credit under the $75 million bilateral credit agreement.

Long-Term Borrowings and Other Financing Instruments

During the nine months ended ~~September~~Sept. 30, ~~2022,~~2023, Xcel Energy Inc. and its utility subsidiaries issued the following:

•Xcel Energy Inc. issued ~~$700~~$800 million of ~~4.60% unsecured senior notes~~5.45% Senior Notes due ~~June~~August 15, 2033.

•PSCo issued $850 million of 5.25% first mortgage bonds due April 1, ~~2032.~~2053.

•NSP-Minnesota issued ~~$500~~$800 million of ~~4.50%~~5.10% first mortgage bonds due May 15, 2053.

•NSP-Wisconsin issued $125 million of 5.30% first mortgage bonds due June ~~1, 2052.~~

•~~PSCo issued $300 million of 4.10% first mortgage bonds due June 1, 2032 and $400 million of 4.50% first mortgage bonds due June 1, 2052.~~15, 2053.

•SPS issued ~~$200 million of 5.15% first mortgage bonds due June 1, 2052.~~

•~~NSP-Wisconsin issued~~ $100 million of ~~4.86%~~6.00% first mortgage bonds due September 15, ~~2052.~~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)~~million in net proceeds and $3 million in transaction fees paid). In ~~the second quarter of~~ 2022, ~~2.13~~4.30 million shares of common stock were issued (approximately ~~$150 million)~~$300 million in net proceeds and $3 million in transaction fees paid). In the nine months ended Sept. 30, 2023, 0.9 million shares were issued (approximately $62 million in net proceeds and $1 million in transaction fees paid). No shares were issued under the ATM program during the quarter ended Sept. 30, 2023. As of Sept. 30, ~~2022,~~2023, approximately ~~$300~~$88 million remained available for sale under the ATM program. Xcel Energy Inc. plans to file a new ATM program in 2023.

~~Other~~ Equity through DRIP and Benefits Program — Xcel Energy ~~Inc.~~ issued ~~$34~~$78 million and ~~$38~~$59 million of equity through the DRIP and benefits programs during the nine months ended Sept. 30, ~~2022~~2023 and ~~2021,~~2022, respectively. The ~~program allows~~programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.


5. Revenues

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


	Three Months Ended Sept. 30, 2023
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,086	$	125	$	16	$	1,227
C&I	1,657		75		7		1,739
Other	42		—		3		45
Total retail	2,785		200		26		3,011
Wholesale	244		—		—		244
Transmission	178		—		—		178
Other	9		33		—		42
Total revenue from contracts with customers	3,216		233		26		3,475
Alternative revenue and other	171		12		4		187
Total revenues	$	3,387	$	245	$	30	$	3,662


	Three Months Ended Sept. 30, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,109	$	181	$	15	$	1,305
C&I	1,734		116		6		1,856
Other	42		—		2		44
Total retail	2,885		297		23		3,205
Wholesale	450		—		—		450
Transmission	210		—		—		210
Other	20		43		—		63
Total revenue from contracts with customers	3,565		340		23		3,928
Alternative revenue and other	134		17		3		154
Total revenues	$	3,699	$	357	$	26	$	4,082


		Three Months Ended Sept. 30, 2021									Nine Months Ended Sept. 30, 2023
(Millions of Dollars)	(Millions of Dollars)	Electric		Natural Gas		All Other		Total		(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types	Major revenue types									Major revenue types
Revenue from contracts with customers:	Revenue from contracts with customers:									Revenue from contracts with customers:
Residential	Residential	$	999	$	133	$	12	$	1,144	Residential	$	2,708	$	1,130	$	44	$	3,882
C&I	C&I	1,515		76		7		1,598		C&I	4,347		622		27		4,996
Other	Other	35		—		1		36		Other	115		—		5		120
Total retail	Total retail	2,549		209		20		2,778		Total retail	7,170		1,752		76		8,998
Wholesale	Wholesale	288		—		—		288		Wholesale	642		—		—		642
Transmission	Transmission	167		—		—		167		Transmission	498		—		—		498
Other	Other	17		45		—		62		Other	22		113		—		135
Total revenue from contracts with customers	Total revenue from contracts with customers	3,021		254		20		3,295		Total revenue from contracts with customers	8,332		1,865		76		10,273
Alternative revenue and other	Alternative revenue and other	155		14		3		172		Alternative revenue and other	419		61		11		491
Total revenues	Total revenues	$	3,176	$	268	$	23	$	3,467	Total revenues	$	8,751	$	1,926	$	87	$	10,764

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	Nine Months Ended Sept. 30, 2022
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	2,723	$	1,100	$	30	$	3,853
C&I	4,385		636		15		5,036
Other	111		—		25		136
Total retail	7,219		1,736		70		9,025
Wholesale	1,027		—		—		1,027
Transmission	518		—		—		518
Other	55		125		—		180
Total revenue from contracts with customers	8,819		1,861		70		10,750
Alternative revenue and other	436		62		9		507
Total revenues	$	9,255	$	1,923	$	79	$	11,257

Nine Months Ended Sept. 30, 2021
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 2,488 $ 774 $ 33 $ 3,295
C&I 3,830 389 22 4,241
Other 96 — 5 101
Total retail 6,414 1,163 60 7,637
Wholesale 1,265 — — 1,265
Transmission 461 — — 461
Other 51 106 — 157
Total revenue from contracts with customers 8,191 1,269 60 9,520
Alternative revenue and other 452 95 9 556
Total revenues $ 8,643 $ 1,364 $ 69 $ 10,076


6. Income Taxes

Reconciliation between the statutory rate and ETR:


		Three Months Ended Sept. 30				Nine Months Ended Sept. 30					Three Months Ended Sept. 30				Nine Months Ended Sept. 30
		2022		2021		2022		2021			2023		2022		2023		2022
Federal statutory rate	Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	State tax (net of federal tax effect)	4.9		5.0		4.9		5.0		State tax (net of federal tax effect)	5.0		4.9		4.9		4.9
Decreases:
(Decreases) increases:										(Decreases) increases:
Wind PTCs (a)	Wind PTCs (a)	(12.3)		(12.1)		(25.2)		(20.0)		Wind PTCs (a)	(13.8)		(12.3)		(27.3)		(25.2)
Plant regulatory differences (b)	Plant regulatory differences (b)	(5.8)		(5.8)		(5.5)		(6.0)		Plant regulatory differences (b)	(5.3)		(5.8)		(5.5)		(5.5)
Other tax credits, net operating loss & tax credits allowances	Other tax credits, net operating loss & tax credits allowances	(1.2)		(1.2)		(1.4)		(1.1)		Other tax credits, net operating loss & tax credits allowances	(1.1)		(1.2)		(1.2)		(1.4)
Other (net)	Other (net)	(0.3)		(0.3)		(0.1)		(0.2)		Other (net)	(0.1)		(0.3)		0.1		(0.1)
Effective income tax rate	Effective income tax rate	6.3	%	6.6	%	(6.3)	%	(1.3)	%	Effective income tax rate	5.7	%	6.3	%	(8.0)	%	(6.3)	%

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

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


7. Earnings Per Share

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

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

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

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

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 Sept. 30		Nine Months Ended Sept. 30			Three Months Ended Sept. 30		Nine Months Ended Sept. 30
(Shares in Millions)	(Shares in Millions)	2022	2021	2022	2021	(Shares in Millions)	2023	2022	2023	2022
Basic	Basic	548	539	546	539	Basic	552	548	551	546
Diluted (a)	Diluted (a)	548	539	546	539	Diluted (a)	552	548	552	546

(a)Diluted common shares outstanding included common stock equivalents of 0.3 million for the three months ended ~~September~~Sept. 30, ~~2022~~2023 and ~~2021, respectively.~~2022. Diluted common shares outstanding included common stock equivalents of 0.2 million and 0.3 million for the nine months ended ~~September~~Sept. 30, ~~2022~~2023 and ~~2021,~~2022, respectively.

~~Table of Contents~~


8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a ~~single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A~~ hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair ~~value is established by this guidance.~~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 ~~highly liquid and~~ actively traded instruments with ~~quoted~~observable actual trading prices.

•Level 2 — Pricing inputs are other than ~~quoted~~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 ~~are~~include those valued with models requiring significant ~~management~~ judgment or estimation.

Specific valuation methods include:

~~Cash equivalents~~— ~~The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.~~

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 ~~fund investments~~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 ~~fund investments~~funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

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

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

Table of Contents

Commodity derivatives — 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 ~~contractual settlements~~contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, ~~or quoted by brokers,~~ 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 3.3 classification.

~~If costs of electric transmission congestion increase or decrease for a given path, the value of that particular instrument will likewise increase or decrease.~~ 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~~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 ~~$900 million~~$1.1 billion and ~~$1.3~~$1 billion as of Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021,~~2022, respectively, and unrealized losses were ~~$133~~$86 million and $7$90 million as of Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021,~~2022, respectively.

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

Sept. 30, 2022
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 37 $ 37 $ — $ — $ — $ 37
Commingled funds 832 — — — 1,167 1,167
Debt securities 696 — 611 9 — 620
Equity securities 409 918 1 — — 919
Total $ 1,974 $ 955 $ 612 $ 9 $ 1,167 $ 2,743

~~(a)~~ Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $214 million of equity method investments and $126 million of rabbi trust assets and miscellaneous investments.

~~Table of Contents~~


		Dec. 31, 2021													Sept. 30, 2023
				Fair Value													Fair Value
(Millions of Dollars)	(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total		(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)	Nuclear decommissioning fund (a)													Nuclear decommissioning fund (a)
Cash equivalents	Cash equivalents	$	64	$	64	$	—	$	—	$	—	$	64	Cash equivalents	$	27	$	27	$	—	$	—	$	—	$	27
Commingled funds	Commingled funds	856		—		—		—		1,294		1,294		Commingled funds	731		—		—		—		1,059		1,059
Debt securities	Debt securities	631		—		666		9		—		675		Debt securities	782		—		719		7		—		726
Equity securities	Equity securities	411		1,222		1		—		—		1,223		Equity securities	509		1,200		2		—		—		1,202
Total	Total	$	1,962	$	1,286	$	667	$	9	$	1,294	$	3,256	Total	$	2,049	$	1,227	$	721	$	7	$	1,059	$	3,014

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes ~~$208~~$244 million of equity method investments and ~~$164~~$135 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 nine months ended Sept. 30, ~~2022~~2023 and ~~2021,~~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 Sept. 30, ~~2022:~~2023:


		Final Contractual Maturity											Final Contractual Maturity
(Millions of Dollars)	(Millions of Dollars)	Due in 1 year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 years		Total		(Millions of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	Debt securities	$	5	$	190	$	227	$	198	$	620	Debt securities	$	10	$	236	$	257	$	223	$	726

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future distributions of ~~its supplemental executive retirement plan and~~a deferred compensation plan.

~~Cost and~~ The fair value of assets held in the rabbi ~~trusts:~~

Sept. 30, 2022
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 1 $ 1 $ — $ — $ 1
Mutual funds 75 73 — — 73
Total $ 76 $ 74 $ — $ — $ 74

Dec. 31, 2021
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 20 $ 20 $ — $ — $ 20
Mutual funds 75 89 — — 89
Total $ 95 $ 109 $ — $ — $ 109

~~(a)~~ ~~Reported~~trusts were $81 million and $80 million at Sept. 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 ~~sheets.~~sheet.

Derivative ~~Instruments~~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 and vehicle fuel~~ prices.

Table of Contents

Interest Rate Derivatives — Xcel Energy enters into ~~various instruments~~contracts that effectively fix the ~~yield or price~~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, ~~for an~~acting as a hedge of changes in market interest rates that will impact specified anticipated debt ~~issuance for a specific period.~~issuances. These derivative instruments are ~~generally~~ designated as cash flow hedges for accounting purposes, with changes in fair value prior to ~~settlement~~occurrence of the hedged transactions recorded as other comprehensive income.

As of Sept. 30, ~~2022,~~2023, accumulated other comprehensive loss related to interest rate derivatives included $2$1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Sept. 30, ~~2022,~~2023, Xcel Energy had no unsettled interest swaps outstanding.

See Note 11 for the financial impact of qualifying interest rate ~~derivatives.~~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 ~~Risk~~ — 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 ~~any~~these margins is determined through state regulatory proceedings as well as the operation of the ~~FERC approved~~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, as well as for trading purposes.~~operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale ~~FTRs, vehicle fuel~~ and ~~weather derivatives.~~FTRs.

The most significant derivative positions outstanding at Sept. 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 ~~may enter~~enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, ~~but may~~the instruments are not betypically designated as qualifying hedging transactions. The classification of unrealized losses or gains ~~or losses for~~on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Sept. 30, ~~2022,~~2023, Xcel Energy had no commodity contracts designated as cash flow hedges.

Xcel Energy also enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.

Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b)

Sept. 30, 2022

Dec. 31, 2021

(Amounts in Millions) (a)(b)

Sept. 30, 2023

Dec. 31, 2022

Megawatt hours of electricity

Million British thermal units of natural gas

151

156

Million British thermal units of natural gas

105

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 inon 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.

~~Table of Contents~~

As of Sept. 30, ~~2022, five~~2023, six of Xcel Energy’s ten most significant counterparties for these activities, comprising ~~$86~~$62 million, or ~~30%~~31%, 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 ~~$61~~$60 million, or ~~22%~~29%, 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~~

One of these significant counterparties, comprising ~~$68~~$44 million, or ~~24%~~22%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. ~~Six~~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 Sept. 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 Sept. 30, 2023 and Dec. 31, 2022, there were approximately $77 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 Sept. 30, 2023 and Dec. 31, 2022.

Table of Contents

Recurring Derivative Fair Value Measurements

Impact of ~~Derivative Activity —~~derivative activity:


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory ~~(Assets)~~Assets and Liabilities
Three Months Ended Sept. 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	4	$	—
Total	$	4	$	—
Other derivative instruments:
Electric commodity	$	—	$	(23)
Natural gas commodity	—		(5)
Total	$	—	$	(28)

Nine Months Ended Sept. 30, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	15	$	—
Total	$	15	$	—
Other derivative instruments:
Electric commodity	$	—	$	(134)
Natural gas commodity	—		(1)
Total	$	—	$	(135)


Three Months Ended Sept. 30, 2022
Derivatives designated as cash flow hedges:


Other derivative instruments:
Electric commodity	$	—	$	6
Natural gas commodity	—		(6)
Total	$	—	$	—

Nine Months Ended Sept. 30, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	21	$	—
Total	$	21	$	—
Other derivative instruments:
Electric commodity	$	—	$	106
Natural gas commodity	—		(3)
Total	$	—	$	103


~~Three Months Ended Sept. 30, 2021~~

~~Derivatives designated as cash flow hedges:Interest rate~~$4 $— ~~Total~~$4 $— ~~Other derivative instruments:Electric commodity~~$— $5 ~~Natural gas commodity~~— 57 ~~Total~~$— $62 ~~Nine Months Ended Sept. 30, 2021Derivatives designated as cash flow hedges:Interest rate~~$5 $— ~~Total~~$5 $— ~~Other derivative instruments:Electric commodity~~$— $18 ~~Natural gas commodity~~— 57 ~~Total~~$— $75


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

Electric commodity											Electric commodity			—			15		(b)	—

Total											Total			$	—		$	15		$	—

Nine Months Ended Sept. 30, 2023											Nine Months Ended Sept. 30, 2023
Derivatives designated as cash flow hedges:											Derivatives designated as cash flow hedges:
Interest rate											Interest rate			$	4	(a)	$	—		$	—
Total											Total			$	4		$	—		$	—
Other derivative instruments:											Other derivative instruments:
Commodity trading											Commodity trading			$	—		$	—		$	(6)	(c)
Electric commodity											Electric commodity			—			109		(b)	—
Natural gas commodity											Natural gas commodity			—			11		(d)	(19)		(d)(e)
Total											Total			$	—		$	120		$	(25)

Three Months Ended Sept. 30, 2022	Three Months Ended Sept. 30, 2022												Three Months Ended Sept. 30, 2022
Derivatives designated as cash flow hedges:	Derivatives designated as cash flow hedges:										Derivatives designated as cash flow hedges:
Interest rate	Interest rate	$	1	(a)	$	—		$	—		Interest rate			$	1	(a)	$	—		$	—
Total	Total	$	1		$	—		$	—		Total			$	1		$	—		$	—
Other derivative instruments:	Other derivative instruments:										Other derivative instruments:
Commodity trading	Commodity trading	$	—		$	—		$	13	(b)	Commodity trading			$	—		$	—		$	13	(c)
Electric commodity	Electric commodity	—			6		(c)	—			Electric commodity			—			6		(b)	—

Total	Total	$	—		$	6		$	13		Total			$	—		$	6		$	13

Nine Months Ended Sept. 30, 2022	Nine Months Ended Sept. 30, 2022										Nine Months Ended Sept. 30, 2022
Derivatives designated as cash flow hedges:	Derivatives designated as cash flow hedges:										Derivatives designated as cash flow hedges:
Interest rate	Interest rate	$	5	(a)	$	—		$	—		Interest rate			$	5	(a)	$	—		$	—
Total	Total	$	5		$	—		$	—		Total			$	5		$	—		$	—
Other derivative instruments:	Other derivative instruments:										Other derivative instruments:
Commodity trading	Commodity trading	$	—		$	—		$	21	(b)	Commodity trading			$	—		$	—		$	21	(c)
Electric commodity	Electric commodity	—			(31)		(c)	—			Electric commodity			—			(31)		(b)	—
Natural gas commodity	Natural gas commodity	—			4		(d)	(17)		(d)(e)	Natural gas commodity			—			4		(d)	(17)		(d)(e)
Total	Total	$	—		$	(27)		$	4		Total			$	—		$	(27)		$	4

Three Months Ended Sept. 30, 2021
Derivatives designated as cash flow hedges:
Interest rate		$	2	(a)	$	—		$	—
Total		$	2		$	—		$	—
Other derivative instruments:
Commodity trading		$	—		$	—		$	1	(b)
Electric commodity		—			3		(c)	—

Total		$	—		$	3		$	1

Nine Months Ended Sept. 30, 2021
Derivatives designated as cash flow hedges:
Interest rate		$	7	(a)	$	—		$	—
Total		$	7		$	—		$	—
Other derivative instruments:
Commodity trading		$	—		$	—		$	49	(b)
Electric commodity		—			(26)		(c)	—
Natural gas commodity		—			8		(d)	(10)		(d)(e)
Total		$	—		$	(18)		$	39

(a)Recorded to interest charges.

(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

~~(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. ~~All~~ 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.

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

(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 nine months ended Sept. 30, ~~2022~~2023 and ~~2021.~~2022.

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~~Credit Related Contingent Features~~—Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-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. At Sept. 30, 2022 and Dec. 31, 2021, there were $5 million and $3 million, respectively, of derivative liabilities with such underlying contract provisions. 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 Sept. 30, 2022 and Dec. 31, 2021, there were approximately $90 million and $64 million, respectively, of derivative liabilities with such underlying contract provisions.

~~Recurring Fair Value Measurements~~ — Derivative assets and liabilities measured at fair value on a recurring basis were as follows:


		Sept. 30, 2022													Dec. 31, 2021																Sept. 30, 2023																Dec. 31, 2022
		Fair Value						Fair Value Total		Netting (a)			Total		Fair Value						Fair Value Total			Netting (a)			Total				Fair Value								Fair Value Total			Netting (a)		Total			Fair Value							Fair Value Total		Netting (a)		Total
(Millions of Dollars)	(Millions of Dollars)	Level 1		Level 2		Level 3						Level 1			Level 2		Level 3						(Millions of Dollars)			Level 1				Level 2				Level 3							Level 1					Level 2			Level 3
Current derivative assets	Current derivative assets																																Current derivative assets

Other derivative instruments:	Other derivative instruments:																								Other derivative instruments:
Commodity trading	Commodity trading	$	53	$	184	$	47	$	284	$	(211)		$	73	$	22	$	137	$	21	$	180		$	(134)		$	46	Commodity trading		$	8			$	80	$	39	$	127		$	(86)	$	41		$	32		$	259	$	33	$	324	$	(242)	$	82
Electric commodity ~~(b)~~	Electric commodity ~~(b)~~	—		—		358		358		(4)			354		—		—		57		57			(1)			56		Electric commodity ~~(b)~~		—				—		99		99			(4)		95			—			—		177		177		(2)		175
Natural gas commodity	Natural gas commodity	—		26		—		26		—			26		—		18		—		18			—			18		Natural gas commodity		—				7		—		7			—		7			—			19		—		19		—		19
Total current derivative assets	Total current derivative assets	$	53	$	210	$	405	$	668	$	(215)		453		$	22	$	155	$	78	$	255		$	(135)		120		Total current derivative assets		$	8			$	87	$	138	$	233		$	(90)	143			$	32		$	278	$	210	$	520	$	(244)	276
PPAs ~~(c)~~(b)	PPAs ~~(c)~~(b)												3														3		PPAs ~~(c)~~(b)															3														3
Current derivative instruments	Current derivative instruments												$	456													$	123	Current derivative instruments															$	146													$	279
Noncurrent derivative assets	Noncurrent derivative assets																												Noncurrent derivative assets
Other derivative instruments:	Other derivative instruments:																								Other derivative instruments:
Commodity trading	Commodity trading	$	50	$	64	$	92	$	206	$	(120)		$	86	$	16	$	63	$	89	$	168		$	(107)		$	61	Commodity trading		$	18			$	36	$	57	$	111		$	(40)	$	71		$	34		$	71	$	74	$	179	$	(89)	$	90

Total noncurrent derivative assets	Total noncurrent derivative assets	$	50	$	64	$	92	$	206	$	(120)		86		$	16	$	63	$	89	$	168		$	(107)		61		Total noncurrent derivative assets		$	18			$	36	$	57	$	111		$	(40)	71			$	34		$	71	$	74	$	179	$	(89)	90
PPAs ~~(c)~~(b)	PPAs ~~(c)~~(b)												4														6		PPAs ~~(c)~~(b)															1														3
Noncurrent derivative instruments	Noncurrent derivative instruments												$	90													$	67	Noncurrent derivative instruments															$	72													$	93


		Sept. 30, 2022													Dec. 31, 2021																					Sept. 30, 2023																									Dec. 31, 2022
		Fair Value						Fair Value Total		Netting (a)			Total		Fair Value						Fair Value Total				Netting (a)					Total						Fair Value													Fair Value Total				Netting (a)				Total				Fair Value												Fair Value Total				Netting (a)			Total
(Millions of Dollars)	(Millions of Dollars)	Level 1		Level 2		Level 3						Level 1			Level 2		Level 3						(Millions of Dollars)				Level 1								Level 2					Level 3												Level 1								Level 2				Level 3
Current derivative liabilities	Current derivative liabilities																																						Current derivative liabilities
Derivatives designated as cash flow hedges:																								Derivatives designated as cash flow hedges:
Interest rate																								Interest rate				$	—				$	—				$	—				$	—			$	—			$	—			$	—			$	1			$	—			$	1			$	—			$	1
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	44	$	223	$	23	$	290	$	(219)		$	71	$	19	$	148	$	20	$	187			$	(143)				$	44	Commodity trading				$	8				$	117			$	7				$	132			$	(90)			$	42			$	29			$	297			$	6			$	332			$	(287)		$	45
Electric commodity (b)		—		—		4		4		(4)			—		—		—		1		1				(1)					—
Electric commodity																								Electric commodity				—					—					4					4				(4)				—				—				—				2				2				(2)				—
Natural gas commodity	Natural gas commodity	—		12		—		12		—			12		—		8		—		8				—					8		Natural gas commodity				—					—				—				—				—				—				—				13				—				13				—			13
Total current derivative liabilities	Total current derivative liabilities	$	44	$	235	$	27	$	306	$	(223)		83		$	19	$	156	$	21	$	196			$	(144)				52		Total current derivative liabilities				$	8				$	117			$	11			$	136			$	(94)			42				$	29			$	311			$	8			$	348			$	(289)		59
PPAs (c)													17																	17
PPAs (b)																								PPAs (b)																											17																								17
Current derivative instruments	Current derivative instruments												$	100																$	69	Current derivative instruments																									$	59																						$	76
Noncurrent derivative liabilities	Noncurrent derivative liabilities																															Noncurrent derivative liabilities
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	59	$	86	$	68	$	213	$	(132)		$	81	$	18	$	48	$	127	$	193			$	(128)				$	65	Commodity trading				$	22				$	41			$	42			$	105			$	(46)			$	59			$	43			$	97			$	41			$	181			$	(98)		$	83
Total noncurrent derivative liabilities	Total noncurrent derivative liabilities	$	59	$	86	$	68	$	213	$	(132)		81		$	18	$	48	$	127	$	193			$	(128)				65		Total noncurrent derivative liabilities				$	22				$	41			$	42			$	105			$	(46)			59				$	43			$	97			$	41			$	181			$	(98)		83
PPAs (c)													33																	40
PPAs (b)																								PPAs (b)																											24																								30
Noncurrent derivative instruments	Noncurrent derivative instruments												$	114																$	105	Noncurrent derivative instruments																									$	83																						$	113

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021, derivatives~~2022, derivative assets and liabilities include ~~$2 million and~~ no obligations to return cash ~~collateral, respectively.~~collateral. At Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021,~~2022, derivative assets and liabilities include rights to reclaim cash collateral of ~~$22~~$12 million and ~~$30~~$53 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)Amounts relate to FTR instruments administered by MISO and SPP (annual auctions occurring in the second quarter). These instruments are utilized/intended to offset the impacts of transmission system congestion. Higher congestion costs have led to an increase in the fair value of FTRs. Due to regulatory recovery, fair values for FTRs are offset/deferred as a regulatory asset or liability and do not have a material impact on net income.

~~(c)During 2006,~~ Xcel Energy ~~qualified these contracts under~~currently applies the normal purchase ~~exception. Based on this qualification,~~exception to qualifying PPAs. Balance relates to specific contracts ~~are no longer adjusted to~~that were previously recognized at fair value prior to applying the normal purchase exception, and ~~the previous carrying value of these contracts is~~are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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Changes in Level 3 commodity derivatives:


		Three Months Ended Sept. 30					Three Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		(Millions of Dollars)	2023		2022
Balance at July 1	Balance at July 1	$	485	$	71	Balance at July 1	$	209	$	485
Purchases / Issuances (a)		4		2
Purchases (a)						Purchases (a)	1		4
Settlements (a)	Settlements (a)	(106)		(53)		Settlements (a)	(50)		(106)
Net transactions recorded during the period:	Net transactions recorded during the period:					Net transactions recorded during the period:
Gains recognized in earnings (b)	Gains recognized in earnings (b)	16		12		Gains recognized in earnings (b)	18		16
Net gains recognized as regulatory assets and liabilities (a)		3		27
Net (losses) gains recognized as regulatory assets and liabilities (a)						Net (losses) gains recognized as regulatory assets and liabilities (a)	(36)		3
Balance at Sept. 30	Balance at Sept. 30	$	402	$	59	Balance at Sept. 30	$	142	$	402

		Nine Months Ended Sept. 30					Nine Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		(Millions of Dollars)	2023		2022
Balance at Jan. 1	Balance at Jan. 1	$	19	$	(49)	Balance at Jan. 1	$	236	$	19
Purchases / Issuances (a)		398		65
Purchases (a)						Purchases (a)	173		398
Settlements (a)	Settlements (a)	(286)		(101)		Settlements (a)	(126)		(286)
Net transactions recorded during the period:	Net transactions recorded during the period:					Net transactions recorded during the period:
Gains recognized in earnings (b)	Gains recognized in earnings (b)	136		59		Gains recognized in earnings (b)	16		136
Net gains recognized as regulatory assets and liabilities (a)		135		85
Net (losses) gains recognized as regulatory assets and liabilities (a)						Net (losses) gains recognized as regulatory assets and liabilities (a)	(157)		135
Balance at Sept. 30	Balance at Sept. 30	$	402	$	59	Balance at Sept. 30	$	142	$	402

(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP (annual auctions occurring in the second quarter). These instruments are utilized/intended to offset the impacts of transmission system congestion. Higher congestion costs have led to an increase in the fair value of FTRs. Due to regulatory recovery, changes in fair value are deferred as a regulatory asset or liability and do not have a material impact on net income.SPP.

(b)Relates to commodity trading and is subject to substantial offsetting losses ofand gains on derivative instruments categorized as levels 1 and 2 in the ~~consolidated~~ income statement.

~~Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments~~ See above tables for the ~~nine months ended Sept. 30, 2022~~income statement impact of derivative activity, including commodity trading gains and ~~2021.~~losses.

Fair Value of Long-Term Debt

~~Other~~As of Sept. 30, 2023, other financial instruments for which the carrying amount did not equal fair value:


		Sept. 30, 2022				Dec. 31, 2021					Sept. 30, 2023				Dec. 31, 2022
(Millions of Dollars)	(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	Long-term debt, including current portion	$	23,960	$	20,560	$	22,380	$	25,232	Long-term debt, including current portion	$	25,961	$	21,484	$	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 Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021~~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 Sept. 30									Three Months Ended Sept. 30
		2022		2021		2022		2021			2023		2022		2023		2022
(Millions of Dollars)	(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits				(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	Service cost	$	24	$	26	$	—	$	—	Service cost	$	18	$	24	$	—	$	—
Interest cost (a)	Interest cost (a)	28		26		3		4		Interest cost (a)	39		28		6		3
Expected return on plan assets (a)	Expected return on plan assets (a)	(52)		(52)		(4)		(4)		Expected return on plan assets (a)	(52)		(52)		(4)		(4)
Amortization of prior service credit (a)	Amortization of prior service credit (a)	—		—		(2)		(2)		Amortization of prior service credit (a)	—		—		—		(2)
Amortization of net loss (a)	Amortization of net loss (a)	19		27		1		1		Amortization of net loss (a)	6		19		—		1
Settlement charge (b)	Settlement charge (b)	55		39		—		—		Settlement charge (b)	—		55		—		—
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	74		66		(2)		(1)		Net periodic benefit cost (credit)	11		74		2		(2)
Effects of regulation	Effects of regulation	(37)		(31)		1		1		Effects of regulation	11		(37)		—		1
Net benefit cost (credit) recognized for financial reporting	Net benefit cost (credit) recognized for financial reporting	$	37	$	35	$	(1)	$	—	Net benefit cost (credit) recognized for financial reporting	$	22	$	37	$	2	$	(1)


		Nine Months Ended Sept. 30									Nine Months Ended Sept. 30
		2022		2021		2022		2021			2023		2022		2023		2022
(Millions of Dollars)	(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits				(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	Service cost	$	73	$	78	$	1	$	1	Service cost	$	55	$	73	$	1	$	1
Interest cost (a)	Interest cost (a)	83		78		11		11		Interest cost (a)	119		83		17		11
Expected return on plan assets (a)	Expected return on plan assets (a)	(156)		(155)		(13)		(13)		Expected return on plan assets (a)	(157)		(156)		(13)		(13)
Amortization of prior service credit (a)	Amortization of prior service credit (a)	(1)		(1)		(5)		(6)		Amortization of prior service credit (a)	(1)		(1)		(1)		(5)
Amortization of net loss (a)	Amortization of net loss (a)	56		81		2		4		Amortization of net loss (a)	17		56		1		2
Settlement charge (b)	Settlement charge (b)	54		39		—		—		Settlement charge (b)	—		54		—		—
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	109		120		(4)		(3)		Net periodic benefit cost (credit)	33		109		5		(4)
Effects of regulation	Effects of regulation	(30)		(32)		2		2		Effects of regulation	25		(30)		—		2
Net benefit cost (credit) recognized for financial reporting	Net benefit cost (credit) recognized for financial reporting	$	79	$	88	$	(2)	$	(1)	Net benefit cost (credit) recognized for financial reporting	$	58	$	79	$	5	$	(2)

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

(b)A settlement charge is required when the amount of ~~all~~ lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the third quarter of 2022, ~~and 2021,~~ as a result of lump-sum distributions during the 2022 ~~and 2021~~ plan ~~years,~~year, Xcel Energy recorded a pension settlement ~~charges~~charge of $55 million, ~~and $39 million, respectively,~~ the majority of which were not recognized in earnings due to the effects of regulation. A total of $7 million ~~and $4 million~~ of those amounts were recorded in other expense in the third quarter of ~~2022 and 2021, respectively.~~2022.

In January ~~2022,~~2023, contributions oftotaling $50 million were made across ~~four of~~ Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during ~~2022.~~2023.

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10. Commitments and Contingencies

~~The following includes commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.~~

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 onin June ~~30,~~ 2022 granting plaintiffs’ class certification. ~~Defendants will work together to prepare and file a petition appealing the class~~ ~~certification ruling to~~In April 2023, the Seventh ~~Circuit.~~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 ~~has concluded that a~~considers the reasonably possible loss ~~is remote for the remaining lawsuit.~~associated with this litigation to be immaterial.

Comanche Unit 3 Litigation — In ~~September~~ 2021, CORE filed a lawsuit in Denver County District ~~Court. CORE alleges~~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 and dismissed CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In February 2022, CORE disclosed that it is claiming in excess of $125 million in total damages.

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

In February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. In September 2023, the court denied PSCo’s motion for summary judgment on other categories of damages and allowed CORE to seek approximately $253 million at trial (before interest), including an alleged $187 million reduction in the value of CORE’s ownership interest in the Comanche 3 facility and $60 million of alleged lost power costs.

On Oct. 25, 2023, the jury awarded CORE lost power damages of $26 million. PSCo recognized $34 million for the verdict in the third quarter of 2023, including estimated interest and other costs. PSCo intends to file an appeal of this decision.

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

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

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

As of Oct. 24, 2023, PSCo is aware of 14 complaints, certain of which have also named Xcel Energy Inc. as a defendant, on behalf of at least 675 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. In September 2023, the Boulder County District Court Judge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, ~~additional undisclosed~~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 per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles. Colorado law 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.

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Colorado law caps punitive or exemplary damages ~~arising from~~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 ~~event.~~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 ~~continues~~are unable to ~~believe CORE's claims are without merit.~~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. In September 2023, NSP-Minnesota, the DOC and the Office of the Attorney General filed rebuttal testimony. The DOC updated its recommendation to $56 million. A final decision by the MPUC is expected in ~~mid-2023.~~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 ~~July 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 February~~ 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.

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In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In August 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. An appeal is now pending at the Eighth Circuit, in which a group of entities is challenging FERC’s decision to order refunds for these charges. SPS has intervened in that appellate proceeding in support of FERC.

In ~~October~~ 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In ~~March~~ 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in ~~April~~ 2018. The FERC subsequently issued a tolling order granting a rehearing for further ~~consideration in May 2018.~~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 ~~October~~ 2020, SPS filed a petition for review of the FERC’s ~~March~~ 2018 ~~order and May 2018 tolling order~~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.~~

~~Contract Termination~~ —~~SPS and LP&L have~~In August 2023, the D.C. Circuit issued 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 is subject to approvaldecision upholding these decisions by ~~the PUCT and~~ FERC. ~~Approval steps are in process, but approval timing from the PUCT is uncertain.~~

Environmental

MGP, Landfill and Disposal Sites

Xcel Energy is investigating, remediating or performing post-closure actions at 14twelve MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under ~~current~~ coal ash ~~regulations (see below).~~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.

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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 Sept. 30, ~~2022,~~2023, Xcel Energy had eight regulated ash units in operation.

PSCo ~~is currently exploring~~has executed an agreement with a third party that ~~would~~will excavate and process ash for beneficial use (at two sites) at a cost of approximately ~~$43~~$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 ~~two~~three Colorado sites). While the results are uncertain, additional costs are estimated to be ~~up to $35~~at least $40 million. ~~An estimated~~A liability has been recorded ~~for the portion of these actions that are estimable,~~ and ~~are~~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 ~~$40~~$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

~~Reasonable Progress Rule:~~Clean Air Act NOx Allowance Allocations — In ~~2016,~~June 2023, after disapproving state implementation plans, the EPA ~~adopted a~~published final regulations under the "Good Neighbor" provisions of the Clean Air Act. The final rule ~~establishing a federal implementation plan for reasonable further progress under the regional haze~~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 ~~state of Texas. The rule imposes sulfur dioxide~~existing allowance allocations. Guidelines are also established for allowance banking and emission ~~limitations which would require~~limit backstops.

While 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~~financial impacts of the final ~~rule.~~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.

~~In 2017,~~SPS and NSP-Minnesota have joined other impacted companies in litigation challenging the ~~Fifth Circuit remanded~~EPA’s disapproval of Texas and Minnesota state implementation plans. Currently, the ~~rule~~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 — The EPA has proposed rules addressing Regional Haze compliance in Texas, which address requirements for reasonable progress at Tolk and BART at Harrington. As proposed, these rules would not require additional controls at either facility, in part due to the ~~EPA for reconsideration (leaving~~conversion of Harrington to gas in 2025 and the ~~stay in effect). In a future rulemaking, the EPA may address whether further sulfur dioxide emission reductions~~planned retirement of Tolk. These rules will be monitored until final versions are ~~necessary.~~published.

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 Sept. 30					Three Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		(Millions of Dollars)	2023		2022
Operating leases	Operating leases					Operating leases
PPA capacity payments	PPA capacity payments	$	59	$	56	PPA capacity payments	$	61	$	59
Other operating leases (a)	Other operating leases (a)	8		2		Other operating leases (a)	11		8
Total operating lease expense (b)	Total operating lease expense (b)	$	67	$	58	Total operating lease expense (b)	$	72	$	67
Finance leases	Finance leases					Finance leases
Amortization of ROU assets	Amortization of ROU assets	$	1	$	2	Amortization of ROU assets	$	1	$	1
Interest expense on lease liability	Interest expense on lease liability	4		4		Interest expense on lease liability	4		4
Total finance lease expense	Total finance lease expense	$	5	$	6	Total finance lease expense	$	5	$	5

(a)Includes short-term lease expense of $1of $1 million for ~~2022~~both 2023 and ~~2021.~~2022.

(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.


		Nine Months Ended Sept. 30					Nine Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		(Millions of Dollars)	2023		2022
Operating leases	Operating leases					Operating leases
PPA capacity payments	PPA capacity payments	$	182	$	170	PPA capacity payments	$	182	$	182
Other operating leases (a)	Other operating leases (a)	28		19		Other operating leases (a)	35		28
Total operating lease expense (b)	Total operating lease expense (b)	$	210	$	189	Total operating lease expense (b)	$	217	$	210
Finance leases	Finance leases					Finance leases
Amortization of ROU assets	Amortization of ROU assets	$	3	$	6	Amortization of ROU assets	$	2	$	3
Interest expense on lease liability	Interest expense on lease liability	12		12		Interest expense on lease liability	12		12
Total finance lease expense	Total finance lease expense	$	15	$	18	Total finance lease expense	$	14	$	15

(a)Includes short-term lease expense of $4of $6 million and $4 million for 2023 and 2022, ~~and 2021.~~respectively.

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Commitments under operating and finance leases as of Sept. 30, ~~2022:~~2023:


(Millions of Dollars)	(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)		(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)
Total minimum obligation	Total minimum obligation	$	1,246	$	166	$	1,412	$	239	Total minimum obligation	$	1,108	$	293	$	1,401	$	220
Interest component of obligation	Interest component of obligation	(174)		(30)		(204)		(169)		Interest component of obligation	(139)		(101)		(240)		(156)
Present value of minimum obligation	Present value of minimum obligation	$	1,072	136		1,208		70		Present value of minimum obligation	$	969	192		1,161		64
Less current portion	Less current portion					(211)		(4)		Less current portion					(231)		(2)
Noncurrent operating and finance lease liabilities	Noncurrent operating and finance lease liabilities					$	997	$	66	Noncurrent operating and finance lease liabilities					$	930	$	62

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

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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.

~~The utility subsidiaries had approxi~~ma~~tely 3,961 MW~~In addition, certain solar PPAs provide an~~d 4,062 MW of capacity~~ option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under ~~long-term~~contract. These specific PPAs ~~at Sept. 30, 2022 and Dec. 31, 2021, respectively, with entities that have been determined to be~~create a variable interest ~~entities.~~ 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 Sept. 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 Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021,~~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 $76 million and $62 million~~and $60 million~~ at Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021,~~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.


11. Other Comprehensive ~~Income (Loss)~~Loss

Changes in accumulated other comprehensive loss, net of tax ~~for the three and nine months ended Sept. 30, 2022 and 2021:~~:


		Three Months Ended Sept. 30, 2022						Three Months Ended Sept. 30, 2021							Three Months Ended Sept. 30, 2023						Three Months Ended Sept. 30, 2022
(Millions of Dollars)	(Millions of Dollars)	Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		(Millions of Dollars)	Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at July 1	Accumulated other comprehensive loss at July 1	$	(57)	$	(46)	$	(103)	$	(80)	$	(55)	$	(135)	Accumulated other comprehensive loss at July 1	$	(44)	$	(38)	$	(82)	$	(57)	$	(46)	$	(103)
Other comprehensive gain before reclassifications	Other comprehensive gain before reclassifications	—		10		10		3		—		3		Other comprehensive gain before reclassifications	3		—		3		—		10		10
Losses reclassified from net accumulated other comprehensive loss:	Losses reclassified from net accumulated other comprehensive loss:													Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)	Interest rate derivatives (a)	1		—		1		2		—		2		Interest rate derivatives (a)	1		—		1		1		—		1
Amortization of net actuarial loss (b)	Amortization of net actuarial loss (b)	—		1		1		—		4		4		Amortization of net actuarial loss (b)	—		—		—		—		1		1
Net current period other comprehensive income	Net current period other comprehensive income	1		11		12		5		4		9		Net current period other comprehensive income	4		—		4		1		11		12
Accumulated other comprehensive loss at Sept. 30	Accumulated other comprehensive loss at Sept. 30	$	(56)	$	(35)	$	(91)	$	(75)	$	(51)	$	(126)	Accumulated other comprehensive loss at Sept. 30	$	(40)	$	(38)	$	(78)	$	(56)	$	(35)	$	(91)


		Nine Months Ended Sept. 30, 2022						Nine Months Ended Sept. 30, 2021							Nine Months Ended Sept. 30, 2023						Nine Months Ended Sept. 30, 2022
(Millions of Dollars)	(Millions of Dollars)	Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		(Millions of Dollars)	Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total		Gains and Losses on Cash Flow Hedges		Defined Benefit Pension and Postretirement Items		Total
Accumulated other comprehensive loss at Jan. 1	Accumulated other comprehensive loss at Jan. 1	$	(75)	$	(48)	$	(123)	$	(85)	$	(56)	$	(141)	Accumulated other comprehensive loss at Jan. 1	$	(54)	$	(39)	$	(93)	$	(75)	$	(48)	$	(123)
Other comprehensive gain before reclassifications	Other comprehensive gain before reclassifications	15		11		26		4		—		4		Other comprehensive gain before reclassifications	11		—		11		15		11		26
Losses reclassified from net accumulated other comprehensive loss:	Losses reclassified from net accumulated other comprehensive loss:													Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)	Interest rate derivatives (a)	4		—		4		6		—		6		Interest rate derivatives (a)	3		—		3		4		—		4
Amortization of net actuarial loss (b)	Amortization of net actuarial loss (b)	—		2		2		—		5		5		Amortization of net actuarial loss (b)	—		1		1		—		2		2
Net current period other comprehensive income	Net current period other comprehensive income	19		13		32		10		5		15		Net current period other comprehensive income	14		1		15		19		13		32
Accumulated other comprehensive loss at Sept. 30	Accumulated other comprehensive loss at Sept. 30	$	(56)	$	(35)	$	(91)	$	(75)	$	(51)	$	(126)	Accumulated other comprehensive loss at Sept. 30	$	(40)	$	(38)	$	(78)	$	(56)	$	(35)	$	(91)

(a)Included in interest charges.

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

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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.

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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 ~~$214~~$244 million and ~~$208~~$219 million as of Sept. 30, ~~2022~~2023 and Dec. 31, ~~2021,~~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 Sept. 30					Three Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		(Millions of Dollars)	2023		2022
Regulated Electric	Regulated Electric					Regulated Electric

Total revenues	Total revenues	$	3,699	$	3,176	Total revenues	$	3,387	$	3,699
Net income	Net income	697		629		Net income	706		697
Regulated Natural Gas	Regulated Natural Gas					Regulated Natural Gas
Operating revenues	Operating revenues	$	357	$	268	Operating revenues	$	245	$	357
Intersegment revenue	Intersegment revenue	1		1		Intersegment revenue	1		1
Total revenues	Total revenues	$	358	$	269	Total revenues	$	246	$	358
Net (loss) income		(7)		10
Net loss						Net loss	(21)		(7)
All Other	All Other					All Other
Total revenues	Total revenues	$	26	$	23	Total revenues	$	30	$	26
Net loss	Net loss	(41)		(30)		Net loss	(29)		(41)
Consolidated Total	Consolidated Total					Consolidated Total
Total revenues	Total revenues	$	4,083	$	3,468	Total revenues	$	3,663	$	4,083
Reconciling eliminations	Reconciling eliminations	(1)		(1)		Reconciling eliminations	(1)		(1)
Total operating revenues	Total operating revenues	$	4,082	$	3,467	Total operating revenues	$	3,662	$	4,082
Net income	Net income	649		609		Net income	656		649

Nine Months Ended Sept. 30
(Millions of Dollars) 2022 2021
Regulated Electric
Operating revenues $ 9,255 $ 8,643
Intersegment revenue 1 1
Total revenues $ 9,256 $ 8,644
Net income 1,312 1,202
Regulated Natural Gas
Operating revenues $ 1,923 $ 1,364
Intersegment revenue 1 2
Total revenues $ 1,924 $ 1,366
Net income 148 161
All Other
Total operating revenue $ 79 $ 69
Net loss (103) (81)
Consolidated Total
Total revenues $ 11,259 $ 10,079
Reconciling eliminations (2) (3)
Total operating revenues $ 11,257 $ 10,076
Net income 1,357 1,282


	Nine Months Ended Sept. 30
(Millions of Dollars)	2023		2022
Regulated Electric
Operating revenues	$	8,751	$	9,255
Intersegment revenue	—		1
Total revenues	$	8,751	$	9,256
Net income	1,352		1,312
Regulated Natural Gas
Operating revenues	$	1,926	$	1,923
Intersegment revenue	3		1
Total revenues	$	1,929	$	1,924
Net income	116		148
All Other
Total revenues	$	87	$	79
Net loss	(106)		(103)
Consolidated Total
Total revenues	$	10,767	$	11,259
Reconciling eliminations	(3)		(2)
Total operating revenues	$	10,764	$	11,257
Net income	1,362		1,357

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

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

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

Non-GAAP Financial Measures

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

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

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

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

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

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. ~~For the three~~These non-GAAP financial measures should not be considered as an alternative to measures calculated and ~~nine months ended Sept. 30, 2022 and 2021, there were no such adjustments to~~reported in accordance with GAAP.

The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	2023		2022		2023		2022
GAAP net income	$	656	$	649	$	1,362	$	1,357
Loss on Comanche Unit 3 litigation	34		—		34		—
Less: tax effect of adjustment	(8)		—		(8)		—
Ongoing earnings	$	682	$	649	$	1,388	$	1,357

Comanche Unit 3 Litigation— As a result of an Oct. 25, 2023 jury verdict in Denver County District Court awarding CORE lost power damages and ~~therefore GAAP earnings equal~~other costs, PSCo recognized a $34 million loss for the matter in the third quarter of 2023. Given the non-recurring nature of this specific item, it has been excluded from ongoing ~~earnings for these periods.~~earnings.


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 Sept. 30				Nine Months Ended Sept. 30					Three Months Ended Sept. 30				Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share	Diluted Earnings (Loss) Per Share	2022		2021		2022		2021		Diluted Earnings (Loss) Per Share	2023		2022		2023		2022
PSCo	PSCo	$	0.45	$	0.40	$	1.02	$	0.96	PSCo	$	0.41	$	0.45	$	0.97	$	1.02
NSP-Minnesota	NSP-Minnesota	0.49		0.46		0.94		0.91		NSP-Minnesota	0.47		0.49		0.95		0.94
SPS	SPS	0.25		0.25		0.52		0.48		SPS	0.30		0.25		0.55		0.52
NSP-Wisconsin	NSP-Wisconsin	0.07		0.07		0.19		0.15		NSP-Wisconsin	0.06		0.07		0.18		0.19
Earnings from equity method investments — WYCO	Earnings from equity method investments — WYCO	0.01		0.01		0.03		0.03		Earnings from equity method investments — WYCO	0.01		0.01		0.03		0.02
Regulated utility (a)	Regulated utility (a)	1.28		1.19		2.69		2.54		Regulated utility (a)	1.25		1.28		2.68		2.69
Xcel Energy Inc. and Other	Xcel Energy Inc. and Other	(0.09)		(0.06)		(0.21)		(0.16)		Xcel Energy Inc. and Other	(0.06)		(0.09)		(0.22)		(0.21)
Total (a)		$	1.18	$	1.13	$	2.48	$	2.38
GAAP diluted EPS (a)										GAAP diluted EPS (a)	1.19		1.18		2.47		2.48
Loss on Comanche Unit 3 litigation										Loss on Comanche Unit 3 litigation	0.05		—		0.05		—
Ongoing diluted EPS (a)										Ongoing diluted EPS (a)	$	1.23	$	1.18	$	2.52	$	2.48

(a)Amounts may not add due to rounding.

Summary of Earnings

Xcel Energy — Xcel Energy’s ~~GAAP~~ third quarter GAAP diluted earnings were $1.19 per share in 2023 compared with $1.18 per share in the same period in 2022, ~~compared with $1.13~~and ongoing diluted earnings were $1.23 per share in ~~2021.~~2023, compared with $1.18 per share in 2022. The increase in ongoing earnings per share was primarily driven by ~~regulatory rate outcomes,~~increased recovery of infrastructure investments, higher sales and demand and lower O&M expenses, partially offset by ~~higher depreciation,~~increased interest charges and ~~O&M expenses. Costs for natural gas sold and transported significantly increased in 2022 primarily due to supply and demand conditions. However, fluctuations~~depreciation. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

PSCo — ~~Earnings~~GAAP diluted earnings decreased $0.04 per share and ongoing diluted earnings increased $0.01 per share for the third quarter. Year-to-date GAAP diluted earnings decreased $0.05 per share and ongoing diluted earnings were flat. Year-to-date ongoing earnings primarily reflect higher recovery of infrastructure investment (electric and natural gas), which were offset by increased depreciation and interest charges.

NSP-Minnesota — GAAP and ongoing earnings decreased $0.02 per share for the third quarter of 2023 and increased $0.01 per share year-to-date. The year-to-date change was driven by increased recovery of electric infrastructure investments, partially offset by higher O&M expenses, interest charges and unfavorable weather.

SPS — GAAP and ongoing earnings increased $0.05 per share for the third quarter of ~~2022~~2023 and ~~$0.06~~$0.03 year-to-date. ~~Higher year-to-date earnings reflect~~The impact of regulatory rate outcomes and sales growth was partially offset by unfavorable weather, increased depreciation and ~~O&M~~interest expenses.

~~NSP-Minnesota~~NSP-Wisconsin — ~~Earnings increased $0.03~~ GAAP and ongoing earnings decreased $0.01 per share for the third quarter of ~~2022~~2023 and year-to-date. ~~The year-to-date increase is primarily due to regulatory rate outcomes, partially offset by increased depreciation, O&M expenses~~Additional electric and ~~a Winter Storm Uri cost disallowance.~~

~~SPS~~ ~~— Earnings~~natural gas infrastructure investment recoveries were flat for the third quarter of 2022 and increased $0.04 per share year-to-date. Higher year-to-date earnings largely reflect regulatory rate outcomes, strong sales growth and favorable weather, partially offset by higher depreciation, O&M expenses and interest ~~charges.~~

~~NSP-Wisconsin~~ — Earnings were flat for the third quarter of 2022 and increased $0.04 per share year-to-date. The year-to-date increase is due to regulatory rate outcomes and sales growth, partially offset by higher depreciation and O&M expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from ~~Energy Impact Partners~~EIP funds equity method investments. ~~Earnings decreased $0.05 per share year-to-date,~~Year-to-date fluctuations are largely attributable to ~~higher~~increased interest ~~charges.~~rates.

2223

Table of Contents

Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in ~~2022~~2023 EPS compared to ~~2021:~~2022:

Diluted Earnings (Loss) Per Share Three Months Ended Sept. 30 Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2021 $ 1.13 $ 2.38
Components of change - 2022 vs. 2021
Higher electric revenues, net of electric fuel and purchased power 0.33 0.67
Lower effective tax rate (ETR) (a)
0.02 0.12
Higher natural gas revenues, net of cost of natural gas sold and transported — 0.04
Higher depreciation and amortization (0.10) (0.30)
Higher O&M expenses (0.06) (0.10)
Higher interest charges (0.04) (0.10)
Higher taxes (other than income taxes) (0.03) (0.07)
Lower other (expense) income (0.02) (0.03)
Other, net (0.05) (0.13)
GAAP and ongoing diluted EPS — 2022 $ 1.18 $ 2.48


Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30		Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2022	$	1.18	$	2.48

Components of change - 2023 vs. 2022
(Lower) higher natural gas revenues, net of cost of natural gas sold and transported	(0.01)		0.07
Lower conservation and demand side management expenses (offset in electric revenues)	0.02		0.06
Higher other income (expense)	0.02		0.05
Lower taxes (other than income taxes)	0.01		0.05
Lower effective tax rate (ETR) (a)	0.01		0.03
Higher depreciation and amortization	(0.02)		—
Higher interest charges	(0.03)		(0.11)
Higher (lower) electric revenues, net of electric fuel and purchased power	0.01		(0.08)
Lower (higher) O&M expenses	0.03		(0.05)
Loss on Comanche Unit 3 litigation	(0.05)		(0.05)
Other, net	0.02		0.02
GAAP diluted EPS — 2023	1.19		2.47
Loss on Comanche Unit 3 litigation	0.05		0.05
Ongoing diluted EPS — 2023 (b)	$	1.23	$	2.52

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

(b)Amounts may not add due to rounding.

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 (mechanism expired in September 2023) and ~~proposed~~ 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, CDD and THI:~~HDD:


		Three Months Ended Sept. 30						Nine Months Ended Sept. 30							Three Months Ended Sept. 30						Nine Months Ended Sept. 30
		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021			2023 vs. Normal		2022 vs. Normal		2023 vs. 2022		2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
HDD	HDD	(27.8)	%	(50.5)	%	36.0	%	8.3	%	0.1	%	7.5	%	HDD	(66.7)	%	(27.8)	%	(55.1)	%	(2.1)	%	8.3	%	(9.3)	%
CDD	CDD	23.0		18.1		13.0		24.7		11.7		17.8		CDD	15.2		23.0		(5.2)		3.2		24.7		(16.1)
THI	THI	1.7		6.2		(4.2)		6.4		25.5		(14.4)		THI	2.6		1.7		—		12.7		6.4		5.1

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


		Three Months Ended Sept. 30						Nine Months Ended Sept. 30							Three Months Ended Sept. 30						Nine Months Ended Sept. 30
		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021			2023 vs. Normal		2022 vs. Normal		2023 vs. 2022		2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
Retail electric	Retail electric	$	0.074	$	0.067	$	0.007	$	0.123	$	0.122	$	0.001	Retail electric	$	0.032	$	0.074	$	(0.042)	$	0.035	$	0.123	$	(0.088)
Decoupling and sales true-up	Decoupling and sales true-up	(0.032)		(0.035)		0.003		(0.055)		(0.076)		0.021		Decoupling and sales true-up	0.007		(0.032)		0.039		(0.015)		(0.055)		0.040
Electric total	Electric total	$	0.042	$	0.032	$	0.010	$	0.068	$	0.046	$	0.022	Electric total	0.039		0.042		(0.003)		0.020		0.068		(0.048)
Firm natural gas	Firm natural gas	—		—		—		0.019		0.004		0.015		Firm natural gas	(0.002)		—		(0.002)		0.024		0.019		0.005
Decoupling														Decoupling	0.001		—		0.001		0.001		—		0.001
Gas total														Gas total	(0.001)		—		(0.001)		0.025		0.019		0.006
Total	Total	$	0.042	$	0.032	$	0.010	$	0.087	$	0.050	$	0.037	Total	$	0.038	$	0.042	$	(0.004)	$	0.045	$	0.087	$	(0.042)

Sales — Sales growth (decline) for actual and weather-normalized sales in ~~2022~~2023 compared to ~~2021:~~2022:


		Three Months Ended Sept. 30											Three Months Ended Sept. 30
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual	Actual											Actual
Electric residential	Electric residential	(1.7)	%	(2.7)	%	7.8	%	(0.1)	%	(0.7)	%	Electric residential	(5.9)	%	0.7	%	3.6	%	0.3	%	(1.4)	%
Electric C&I	Electric C&I	(2.3)		0.2		7.2		3.7		1.6		Electric C&I	(2.0)		(1.6)		6.5		(2.3)		0.5
Total retail electric sales	Total retail electric sales	(2.0)		(0.8)		7.3		2.6		0.9		Total retail electric sales	(3.4)		(0.8)		5.7		(1.6)		(0.1)
Firm natural gas sales	Firm natural gas sales	(1.6)		—		N/A		2.3		(0.9)		Firm natural gas sales	1.3		—		N/A		(3.2)		0.6

Three Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential (4.6) % 0.5 % 3.3 % (0.1) % (1.1) %
Electric C&I (3.2) 0.4 6.4 3.5 1.2
Total retail electric sales (3.7) 0.4 5.9 2.5 0.5
Firm natural gas sales (1.5) (2.2) N/A — (1.6)


		Nine Months Ended Sept. 30											Three Months Ended Sept. 30
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Weather-Normalized												Weather-Normalized
Electric residential	Electric residential	(2.9)	%	(1.4)	%	4.9	%	1.3	%	(0.9)	%	Electric residential	5.6	%	2.6	%	1.8	%	0.4	%	3.4	%
Electric C&I	Electric C&I	(0.3)		2.3		9.6		3.6		3.6		Electric C&I	1.7		(1.8)		6.0		(2.5)		1.3
Total retail electric sales	Total retail electric sales	(1.2)		1.1		8.6		2.9		2.2		Total retail electric sales	3.0		(0.4)		4.9		(1.7)		1.9
Firm natural gas sales	Firm natural gas sales	(3.4)		19.9		N/A		20.2		4.9		Firm natural gas sales	2.4		3.0		N/A		0.3		2.5

2324

Table of Contents


		Nine Months Ended Sept. 30
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			Nine Months Ended Sept. 30
Weather-Normalized
													PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual												Actual
Electric residential	Electric residential	(3.7)	%	0.6	%	0.7	%	0.6	%	(1.0)	%	Electric residential	(4.4)	%	(0.1)	%	(3.3)	%	(2.6)	%	(2.4)	%
Electric C&I	Electric C&I	(0.5)		2.7		9.0		3.8		3.5		Electric C&I	(2.1)		(0.7)		5.5		(0.3)		0.7
Total retail electric sales	Total retail electric sales	(1.6)		2.0		7.4		2.8		2.2		Total retail electric sales	(2.9)		(0.5)		3.8		(1.0)		(0.2)
Firm natural gas sales	Firm natural gas sales	(2.4)		6.0		N/A		7.4		0.9		Firm natural gas sales	4.9		(10.7)		N/A		(12.7)		(1.6)



	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	1.4	%	0.6	%	0.9	%	(0.5)	%	0.8	%
Electric C&I	(0.2)		(0.9)		5.7		(0.2)		1.2
Total retail electric sales	0.3		(0.4)		4.7		(0.3)		1.1
Firm natural gas sales	1.6		(1.4)		N/A		(1.9)		0.4

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

•PSCo — Residential sales ~~declined~~increased due to ~~decreased use per customer, partially offset by~~ a ~~1.1%~~1.3% increase in customers. The C&I sales decline was ~~attributable~~related to decreased use per customer, primarily in the manufacturing ~~sector (largely due to an alternative generation arrangement with a significant customer), partially offset by strong small C&I sales in the professional services~~ and ~~health care~~agricultural sectors.

•NSP-Minnesota — Residential sales ~~growth reflects~~increased due to a ~~1.2%~~1.1% increase in customers, partially offset by a decreased use per customer. ~~Growth in~~ C&I sales ~~was primarily~~declined due to ~~higher~~decreased use per customer, ~~particularly in the manufacturing, real estate and leasing, and food service sectors.~~due to general economic conditions.

•SPS — Residential sales growth was primarily attributable to a ~~1.0%~~0.7% increase in customers ~~partially offset by a lower~~and increased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector.

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

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

•Natural gas sales reflect a ~~higher~~lower use per residential customer in all jurisdictions, partially offset by an increase in C&I use per customer ~~experienced primarily~~ in ~~NSP-Minnesota and NSP-Wisconsin partially offset by a decrease in PSCo (lower residential use per customer).~~PSCo. In addition, residential and C&I customer growth was 1.2% and ~~0.5%~~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 that recover fuel expenses.~~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 and explanation of the changes are listed as follows:~~margin:


		Three Months Ended Sept. 30				Nine Months Ended Sept. 30					Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		2022		2021		(Millions of Dollars)	2023		2022		2023		2022
Electric revenues	Electric revenues	$	3,699	$	3,176	$	9,255	$	8,643	Electric revenues	$	3,387	$	3,699	$	8,751	$	9,255
Electric fuel and purchased power	Electric fuel and purchased power	(1,497)		(1,210)		(3,772)		(3,643)		Electric fuel and purchased power	(1,181)		(1,497)		(3,328)		(3,772)
Electric margin	Electric margin	$	2,202	$	1,966	$	5,483	$	5,000	Electric margin	$	2,206	$	2,202	$	5,423	$	5,483


(Millions of Dollars)	(Millions of Dollars)	Three Months Ended Sept. 30, 2022 vs. 2021		Nine Months Ended Sept. 30, 2022 vs. 2021		(Millions of Dollars)	Three Months Ended Sept. 30, 2023 vs. 2022		Nine Months Ended Sept. 30, 2023 vs. 2022
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)		$	165	$	361
Revenue recognition for the Texas rate case surcharge (a)	Revenue recognition for the Texas rate case surcharge (a)	—		85		Revenue recognition for the Texas rate case surcharge (a)	$	—	$	(85)
Sales and demand (b)		24		84

Non-fuel riders		8		48
Conservation and demand side management (offset in expenses)		9		31
Wholesale transmission (net)		19		25
Conservation and demand side management (offset in expense)						Conservation and demand side management (offset in expense)	(14)		(48)
Estimated impact of weather (net of decoupling/sales true-up)	Estimated impact of weather (net of decoupling/sales true-up)	7		16		Estimated impact of weather (net of decoupling/sales true-up)	(2)		(34)
PTCs flowed back to customers (offset by lower ETR)	PTCs flowed back to customers (offset by lower ETR)	(17)		(120)		PTCs flowed back to customers (offset by lower ETR)	(10)		(33)
Proprietary commodity trading, net of sharing (c)		(1)		(33)
Non-fuel riders						Non-fuel riders	39		70
Sales and demand (b)						Sales and demand (b)	18		38
Wholesale transmission (net)						Wholesale transmission (net)	(8)		15
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, Wisconsin, South Dakota and Michigan)						Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, Wisconsin, South Dakota and Michigan)	1		13

Other (net)	Other (net)	22		(14)		Other (net)	(20)		4
Total increase		$	236	$	483

Total increase (decrease)						Total increase (decrease)	$	4	$	(60)

(a)~~Recognition~~The decline in electric margin is due to the recognition of ~~revenue from~~ the Texas rate case outcome isin the second quarter of 2022, which was largely offset by recognition of previously deferred ~~costs, see Public Utility Regulation for additional information.~~costs.

(b)Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September) and ~~proposed~~ sales true-up mechanism in Minnesota.

~~(c)Includes $27 million of net gains recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri.~~

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 and explanation of the changes are listed as follows:~~margin:


		Three Months Ended Sept. 30				Nine Months Ended Sept. 30					Three Months Ended Sept. 30				Nine Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2022		2021		2022		2021		(Millions of Dollars)	2023		2022		2023		2022
Natural gas revenues	Natural gas revenues	$	357	$	268	$	1,923	$	1,364	Natural gas revenues	$	245	$	357	$	1,926	$	1,923
Cost of natural gas sold and transported	Cost of natural gas sold and transported	(173)		(86)		(1,134)		(603)		Cost of natural gas sold and transported	(70)		(173)		(1,084)		(1,134)
Natural gas margin	Natural gas margin	$	184	$	182	$	789	$	761	Natural gas margin	$	175	$	184	$	842	$	789

(Millions of Dollars) Three Months Ended Sept. 30, 2022 vs. 2021 Nine Months Ended Sept. 30, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Wisconsin, North Dakota, Colorado) $ 2 $ 16
Estimated impact of weather — 11
Conservation revenue (offset in expenses) 2 9
Infrastructure and integrity riders 4 7
Winter Storm Uri disallowances (7) (20)
Other (net) 1 5
Total increase $ 2 $ 28


(Millions of Dollars)	Three Months Ended Sept. 30, 2023 vs. 2022		Nine Months Ended Sept. 30, 2023 vs. 2022
Regulatory rate outcomes (Colorado and Wisconsin)	$	—	$	49
Estimated impact of weather (net of decoupling)	—		5





Other (net)	(9)		(1)
Total (decrease) increase	$	(9)	$	53

2425

Table of Contents

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses ~~increased $43~~decreased $25 million for the third quarter and ~~$75~~increased $37 million year-to-date. ~~O&M costs increased~~The year-to-date increase was primarily due to ~~recognition~~higher bad debt expenses; the impact of ~~previously~~inflationary pressures, including labor increases and insurance, and unplanned maintenance at generating plants, offset by the change in deferred ~~amounts related to~~costs associated with the ~~2021~~ Texas Electric Rate ~~Case, additional investments~~Cases (offset in ~~technology~~electric revenues) and ~~customer programs, higher costs for storms and vegetation~~impact of management ~~and inflationary impacts. These increases were partially offset by a reduction in employee benefit costs and timing of certain power plant overhaul costs.~~cost containment actions.

Depreciation and Amortization — Depreciation and amortization increased ~~$70~~$11 million for the third quarter and ~~$221 million~~was flat year-to-date. ~~The increase was primarily driven~~Year-to-date activity is related to system expansion, offset by ~~normal system expansion,~~the recognition of previously deferred depreciation costs ~~related to~~associated with the Texas Electric Rate Case in 2022 (approximately $40 million) and ~~several wind farms going into service.~~depreciation life extensions implemented in the Minnesota Electric Rate Case.

~~Other (Expense)~~Taxes (other than Income Taxes) — ~~— Other (expense) income~~Taxes decreased ~~$12~~$5 million for the third quarter and ~~$25~~$34 million year-to-date, primarily due to deferrals related to the Minnesota Electric Rate Case and the recognition of previously deferred costs associated with the Texas Electric Rate Case in 2022, partially offset by an increase in Colorado property tax expense.

Other Income (Expense) —Other income (expense) increased $18 million for the third quarter and $39 million year-to-date, largely related to interest earned on cash balances and rabbi trust performance, which is ~~primarily~~partially offset in O&M expenses (employee benefit costs).

Interest Charges — Interest charges increased ~~$33~~$25 million for the third quarter and ~~$77~~$85 million year-to-date, largely due to higher interest rates and increased long-term debt levels, ~~to fund capital investments.~~

~~Income Taxes~~ — ~~Income tax expense increased $1 million for~~partially offset by the ~~third quarter and income tax benefit increased $63 million year-to-date. The year-to-date increase was primarily driven by an increase~~recognition of previously deferred costs associated with the Texas Electric Rate Case in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.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, ~~2021~~2022 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

NSP-Minnesota

Upcoming, Pending and Recently Concluded Regulatory Proceedings

2022 Minnesota Electric Rate Case — InIn October 2021, NSP-Minnesota filed a three-year electric rate case with the ~~MPUC.~~Minnesota Public Utilities Commission (MPUC). The rate ~~case is~~request was based on a ~~requested~~ ROE of 10.2%, a 52.5% equity ratio and forward test years.

~~The request is detailed as follows:~~

(Amounts in Millions, Except Percentages) 2022 2023 2024 Total
Annual rate increase requested $ 396 $ 150 $ 131 $ 677
Increase percentage 12.2 % 4.8 % 4.2 % 21.2 %
Rate base $ 10,931 $ 11,446 $ 11,918 N/A

In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. ~~On Sept. 30,~~In November 2022, NSP-Minnesota ~~requested an incremental increase~~revised its rate request to ~~interim rates of $122~~$498 million ~~effective Jan. 1, 2023.~~ over three years.~~On Oct. 21, 2022, intervening parties to the rate case filed comments recommending~~

In July 2023, the MPUC ~~deny NSP-Minnesota’s request. A~~approved a three-year rate increase of approximately $316 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC ~~decision is expected in late 2022.~~also approved a continuation of the sales true-up mechanism.

In October ~~2022, nine parties filed testimony. The DOC, OAG, XLI, CUB and JSC were~~2023, the ~~only parties~~MPUC denied NSP-Minnesota’s request for reconsideration of certain aspects of the decision. NSP-Minnesota plans to ~~quantify recommended financial adjustments. XLI recommended $112 million~~file an appeal of the decision to the Minnesota Court of Appeals in ~~proposed adjustments, based on reducing ROE, reducing recovery of incentive compensation and not including the prepaid pension asset in~~November 2023.

Interim rate ~~base. CUB recommended adjustments based on reducing ROE. Other parties provided specific issue recommendations.~~

~~Proposed DOC modifications~~refunds are scheduled to ~~NSP-Minnesota’s request:~~

(Millions of Dollars) 2022 2023 2024
NSP-Minnesota’s filed base revenue request $ 396 $ 546 $ 677
Recommended adjustments:
Rate base and rate of return (a)
(71) (58) (57)
MISO capacity credits (55) (94) (94)
Monticello and wind farm life extension (21) (54) (51)
PTC and ND ITC forecast (28) (40) (43)
Property tax (14) (22) (32)
Prepaid pension asset and liability (13) (21) (32)
O&M expenses (18) (26) (29)
Other, net (48) (57) (65)
Total adjustments (268) (372) (403)
Total proposed revenue change $ 128 $ 174 $ 274

~~(a)Included~~begin in the ~~rate base and rate~~first quarter of ~~return adjustments is an annual proposed increase in the cost of debt.~~

~~Positions on NSP-Minnesota’s filed rate request:~~

Recommended Position DOC XLI CUB JSC
ROE 9.25 % 9.17 % 8.80-9.00 % 9.06 %
Equity 52.5 % N/A N/A N/A

~~Next steps in the procedural schedule are expected to be as follows:~~2024.

•~~Rebuttal testimony: Nov. 8, 2022.~~

•~~Hearing: Dec. 13-16, 2022.~~

•~~ALJ Report: March 31, 2023.~~

•~~MPUC Order: June 30, 2023.~~

~~Table of Contents~~

~~2022~~2024 Minnesota Natural Gas Rate Case —~~In November 2021,~~ NSP-Minnesota ~~filed~~ plans to file a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.

~~In October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following key terms:~~

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

•~~Revenue decoupling mechanism.~~

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

•~~ROE of 9.57%.~~

•~~Equity ratio of 52.5%.~~

~~A hearing is scheduled for the fourth quarter of 2022 and a MPUC order is expected~~case in ~~the first half of~~November 2023.

~~2021 North Dakota Natural Gas Rate Case —~~ In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.5%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a rate base of $124 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.

~~In May 2022, NSP-Minnesota and NDPSC Staff reached a natural gas settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio. A NDPSC decision is pending.~~

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

~~Wind Repowering~~ — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval. In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects.

~~Wind PPA Buyout~~ — In July 2022, NSP-Minnesota requested approval from the MPUC for updated agreements with ALLETE Clean Energy to purchase the repowered 100 MW Northern Wind Facility and 22 MW Rock Aetna Facility. In October 2022, the MPUC approved NSP-Minnesota’s updated acquisition agreements, which included an increase in the purchase price. The price increase is more than offset by the passage of the IRA, resulting in greater savings for customers than the original approval.

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. ~~A MPUC decision is expected in 2023.~~

~~Sherco Solar Proposal~~ — In ~~September 2022,~~June 2023, NSP-Minnesota filed to withdraw its request, which the MPUC approved ~~NSP-Minnesota’s proposal to add 460 MW of solar facilities at the Sherco site. The project is expected to cost approximately $690 million (two phases to be completed~~ in ~~2024 and 2025). As a result of the IRA, the levelized cost of the project is expected to be approximately 30% lower than previously estimated.~~August.

~~2022 RES Electric Rider —~~ In November 2021, NSP-Minnesota filed the RES Rider. In September 2022, the MPUC approved the requested amount of $264 million, which includes a true-up (2020 and 2021 riders) of $154 million and the 2022 requested amount of $110 million.

~~2022 GUIC Natural Gas Rider —~~ ~~In October 2021, NSP-Minnesota filed the GUIC Rider for an amount of $27 million. A MPUC decision is pending.~~

~~2021 GUIC Natural Gas Rider —~~ ~~In October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million. A MPUC decision is pending.~~

~~2022 TCR Electric Rider —~~ ~~In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million. A MPUC decision is pending.~~

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, ~~2021~~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, ~~2021,~~2022, appropriately represent, in all material respects, the current status of nuclear power ~~operations, and are incorporated by reference.~~operations.

~~PSCo~~NSP-Wisconsin

Pending ~~and Recently Concluded~~ Regulatory Proceedings

~~Colorado Natural Gas~~Wisconsin Rate Case — In ~~January 2022, PSCo~~April 2023, NSP-Wisconsin filed a ~~request with the CPUC~~Wisconsin rate case seeking ~~a net~~an electric increase ~~to retail~~of $40 million (rate increase of 4.8%) and a natural gas ~~rates~~increase of ~~$107 million.~~$9 million (rate increase of 5.3%). The ~~total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request~~rate filing is based on a 2024 forecast test year, a ROE of 10.25% ~~ROE,~~, an equity ratio of ~~55.66%~~52.5% and a ~~2022 current test year with a projected~~forecasted average net rate base of ~~$3.6 billion. PSCo has requested~~approximately $2.1 billion for the electric utility and $284 million for the natural gas utility.

On Sept. 1, 2023, the PSCW Staff recommended an electric base rate decrease of $3 million or (0.3)% when including depreciation, fuel and purchased power adjustments and a ~~proposed effective date of Nov. 1, 2022.~~

~~Additionally, PSCo’s request includes step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.~~

~~In October 2022, the CPUC issued a written decision approving a~~natural gas rate increase ~~net~~ of ~~rider roll-ins of $64 million.~~$5 million, or 3.1%. The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million of incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. PSCo anticipates usingrecommendation was based on a ROE of ~~9.2%~~9.7% and an equity ratio of ~~53.8%~~52.5%. ~~The CPUC denied the 2023-2024 step increases.~~

~~Table of Contents~~

In September 2023, NSP-Wisconsin filed rebuttal testimony and updated its request for depreciation life extensions and other updates. NSP-Wisconsin revised its requested rate increase to $25 million for the electric utility and $7 million for the natural gas utility. NSP-Wisconsin will update forecasted fuel costs before the Commission decision. Prudently incurred 2024 fuel costs will be trued up to actuals in a fuel reconciliation process, subject to a 2% band.

A PSCW decision is anticipated late fourth quarter 2023 with new rates effective in January 2024.

NSP System

2022 Upper Midwest IRP Resource Acquisition

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

~~Colorado Power Pathway Settlement~~— •In ~~June~~August 2022, NSP-Minnesota and NSP-Wisconsin jointly filed an RFP seeking at least 900 MW of solar or solar plus storage capacity. In May 2023, NSP-Minnesota filed a recommended portfolio, which proposed an additional 250 MW of self-build solar generation at the ~~CPUC issued~~site of our retiring Sherco coal units and a ~~final written order issuing~~100 MW solar PPA located in Wisconsin as part of the ~~CPCN~~resource plan RFP. In September 2023, the MPUC approved the request, subject to a cost cap based on projected costs for the ~~Pathway Project. Key decisions include:~~Sherco solar project.

•~~The CPUC approved PSCo’s cost estimate~~In the second quarter of ~~$1.7 billion~~2023, NSP-Minnesota initiated the process with the MPUC for acquisition of 800 MW of firm dispatchable resources. NSP-Minnesota and ~~recovery through the transmission rider.~~

•~~The CPUC modified the PIMs~~other companies can submit proposed in the settlement agreement, which focused on cost controls, to add a separate mechanism to further incentivize timely delivery of the Pathway Project segments. The CPUC also increased the magnitude of the PIMs.

•The CPUC granted conditional approval for the 345 kilovolt May Valley-Longhorn line extension, pending the level of renewables being added in that region through PSCo’s resource plan. The initial cost estimate for the extension is approximately $250 million.

~~Colorado Resource Plan Settlement~~— In August 2022, the CPUC issued a written approval of a revised 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 mixresources by ~~2030. The CPUC deferred~~January 2024. NSP-Minnesota expects a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo expects to commence the request for proposal process for generation resources and file a recovery method docket inby the fourth quarter of ~~2022.~~

~~Key settlement terms include:~~

•~~Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).~~2024.

•~~Conversion~~In July 2023, NSP-Wisconsin issued an RFP seeking approximately 650 MW of solar and/or solar plus storage development assets that will be developed in the ~~Pawnee coal plant~~2027-2029 timeframe to ~~natural gas by no later than Jan. 1, 2026.~~replace the nameplate capacity associated with NSP-Minnesota’s retiring King Generating Station. The RFP closed in September 2023.

•~~Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025.~~

•~~Addition of ~2,400~~In October 2023, NSP-Minnesota issued an RFP seeking approximately 1,200 MW of ~~wind.~~

•~~Addition of ~1,600 MW of universal-scale solar.~~

•~~Addition of 400 MW of storage.~~

•~~Addition of 1,300 MW of flexible, dispatchable generation.~~

•~~Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.~~

~~Colorado Partial Settlement —~~ ~~In October~~ ~~2021, PSCo filed a comprehensive settlement with the CPUC Staff~~wind development assets to replace capacity and ~~the Colorado Energy Office, which proposed to address four outstanding regulatory items, including recovery of fuel costs related to Winter Storm Uri, disputed revenue~~reutilize interconnection rights associated with the ~~2020 electric decoupling pilot program year, replacement power costs associated with an extended outage at Comanche Unit 3 during 2020 and deferred customer bad debt balances associated with COVID-19. In July 2022, the CPUC approved the settlement, with an $8 million disallowance relating~~company’s retiring Sherco coal facilities. The RFP is scheduled to ~~the Winter Storm Uri fuel costs.~~

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

~~In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of decoupling. See Colorado Partial Settlement disclosure above.~~

~~As of Sept. 30, 2022, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021~~close in December 2023 and the ~~first, second and third quarters~~Company expects to file for approval of ~~2022 results.~~

In April 2022, PSCo made its annual filing. In May 2022, the UCA filed a protest raising issues relating to the Winter Storm Uri settlement and the soft cap components of the decoupling program. On May 25, 2022 the CPUC found merit in UCA’s protest, suspended PSCo’s advice letter and referred the matter to the ALJ. A hearing is expected to take place in the fourth quarter of 2022 and an ALJ recommendation is expected in the first quarter of 2023.

~~2019 Electric Rate Case Appeal~~ ~~— In August 2020, PSCo filed an appeal~~recommended projects when contract negotiations with ~~the Denver District Court seeking a review of CPUC decisions on gains and losses on sales of assets and other items.~~ ~~In January 2022, the court issued its decision that the CPUC’s approach to gains and losses on certain sales of assets w~~as legally erroneous and confiscatory to PSCo and set aside and remanded the issue for further consideration. In October 2022, the CPUC approved PSCo’s proposed methodology to allocate gains and losses.

~~GCA NOPR~~— In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has reopened the GCA NOPR matter and proposed a 2 step process aimed at 1) considering near term process changes to the GCA usedselected bidders are complete by various utilities and 2) a longer term process to evaluate potential performance incentive GCA structures to be filed by Nov. 1, 2022. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration.

~~Natural Gas Planning NOPR~~ — In October 2021, the CPUC issued a NOPR to implement recent state legislation requiring natural gas utilities to develop clean heat plans as a means to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the proposed rules included new comprehensive natural gas infrastructure planning requirements and related CPCN application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans. The CPUC staff will provide proposed rules in the fourth quarter of 2022.mid-2024.

~~SPS~~PSCo

Pending and Recently Concluded Regulatory Proceedings

~~2021 Texas~~Colorado Electric Rate Case — — In ~~2021, SPS~~November 2022, PSCo filed ana 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 previously recovered through various rider mechanisms. The request was 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.

In September 2023, the ~~PUCT and its municipalities seeking an increase in base rates of approximately $140 million. In May 2022, the PUCT~~CPUC approved a settlement between ~~SPS~~PSCo and ~~intervening~~various parties, which ~~reflects~~included the following terms:

•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.

•~~Base rate increase~~Weighted-average cost of ~~$89 million effective retroactively to March 15, 2021.~~capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE).

•~~A 9.35% ROE and 7.01% weighted average cost~~Termination of ~~capital for AFUDC purposes only.~~the revenue decoupling pilot with implementation of new rates.

•~~Depreciation lives~~Continuation of previously authorized trackers and deferrals.

•Collection of PSCo’s requested 2023 TCA revenues, previously suspended by the CPUC. Beginning in 2024, projects eligible for ~~Tolk accelerated~~recovery will be limited to ~~2034~~projects which increase transmission capacity or are part of an approved wildfire mitigation plan.

Rates became effective in September 2023.

Colorado Resource Plan— In August 2022, the CPUC approved a settlement for the Colorado Resource Plan among PSCo and ~~Harrington~~various intervenors. This settlement provides for an expected carbon reduction and the retirement of PSCo’s remaining coal ~~assets accelerated to 2024.~~plant by the end of 2030.

In ~~July~~September 2023, PSCo filed its recommended Preferred Plan. The filing also includes several other alternative scenarios. PSCo’s Preferred Plan results in the exit of coal by the end of 2030, roughly doubling wind and solar energy from 2022 ~~SPS~~levels, and reduction of greenhouse gas emissions by more than 80% from 2005 levels. It also reflects an average annual rate impact of approximately 2.3% which is inclusive of generation and transmission network and interconnection costs.

The Preferred Plan includes the following resources:


Generation Resource (in MW)	Company Owned	PPAs	Total
Wind Resources	2,531	875	3,406
Solar	1,109	860	1,969
Storage	500	670	1,170
Natural Gas	628	—	628
Biomass	19	—	19
Total	4,787	2,405	7,192

If approved by the CPUC, Xcel Energy expects to invest $7.9 billion in generation resources. In addition, the plan requires approximately $2.9 billion of incremental investments in transmission capacity upgrades and new lines to fully integrate the renewable generation.

The CPUC is expected to render a decision on the recommended Preferred Plan by the end of 2023 or in early 2024.

ECA Fuel Recovery — In December 2022, PSCo filed its first quarter 2023 ECA Advice Letter, which sought to ~~surcharge~~recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of one quarter, as more typical). In December 2022, the ~~final~~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 and May 2023, PSCo submitted interim ECA filings which included $70 million and $25 million, respectively, of the 2022 under-recovered ~~amount, estimated~~costs to be ~~approximately $85 million, substantially offset~~collected over the remainder of 2023.

In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million. This was opposed by the ~~recognition of previously deferred costs.~~UCA. The ~~impact of the retroactive amounts~~ALJ held a hearing in October 2023 and is ~~as follows:~~


~~(Millions of Dollars)~~	~~Nine Months Ended Sept. 30, 2022~~
~~Revenue surcharge accrual~~	$	85
~~Depreciation and amortization~~	~~(43)~~
~~O&M expenses~~	~~(16)~~
~~Interest expense~~	~~(12)~~
~~Taxes other than income taxes~~	~~(10)~~
~~Fuel and purchased power~~	~~(2)~~

expected to issue a recommended decision in late 2023 or early 2024.

Table of Contents

Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines). 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 October 2023, the NMPRC approved a settlement between SPS, NMPRC Staff, and various parties, which included the following terms:

•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.

Rates went into effect in October 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. 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.

In September 2023, SPS and various parties reached a settlement in principle regarding the overall revenue requirement and key terms. The parties are still completing cost allocation and rate design settlement details and will file the settlement assuming finalization of remaining issues.

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. In September 2023, SPS received 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.

New Mexico Resource Plan— On Oct. 13, 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and secures replacement energy and capacity for retiring resources. SPS presented three load forecasts ranging from a low load growth scenario to a stakeholder-driven high load growth forecast (the “Electrification Forecast”). Based on these forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging fromapproximately5,300 MW to 10,200 MW by 2030. Upon acceptance of the IRP, SPS expects to issue an RFP for new generation in mid-2024. The RFP will be evaluated in the latter half of 2024 with project selection expected in early 2025.

Other

Supply Chain

Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. ~~For example, availability of certain types of transformers has been significantly impacted and in some cases may result in delays in new customer connections as we work to address the shortage.~~ 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.

~~Advanced Metering Infrastructure Implementation~~Electric Meters and Transformers

Supply chain issues associated with semi-conductors have delayed the availability of advanced infrastructure ~~electric~~ meters, which ~~has~~ led to a reduced number of meters deployed in 2022. ~~Impacts to~~While there have been improvements in the 2023 deployment ~~schedule are currently being evaluated.~~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,~~August 2023, the U.S. Department of Commerce ~~initiated an~~completed its anti-circumvention investigation and concluded that ~~would subject~~ CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia ~~with potential~~would be subject to incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.

~~Since that time, an~~An interim stay on tariffs ~~has been issued~~remains in effect until June 2024 and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota ~~which was recently approved by the MPUC~~ and certain PPAs in ~~PSCo which are pending regulatory approval.~~

~~Marshall Wildfire~~

~~In December 2021,~~PSCo. Further policy action, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lineschange in the ~~ignition area, and nothing the Company has seen to this point indicates that our equipment or operations caused the fire.~~

~~In Colorado, the standard~~interim stay of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under ~~a commission approved wildfire mitigation plan and carries wildfire liability insurance.~~

In March 2022, a class action suit was filed in Boulder County pertaining to the Marshall Fire. In the remote event PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage and have a material adverse effect on our financial condition, results of operations or cash flows. In June 2022, Plaintiffs served the class action lawsuit. In July 2022, PSCo filed a Motion to Dismiss.

~~Comanche Unit 3 Outage —In late January 2022, PSCo experienced an outage at the Comanche Unit 3 coal plant.~~The plant returned to service in June 2022. PSCo will not seek recovery of the $10 million of incremental replacement power costs incurred during the outage, which reflects a true-up to final incurred costs in the third quarter of 2022.

~~MISO Capacity Credits —~~ The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing and is expected to generate revenues of approximately $90 million in 2022 and approximately $60 million in 2023. During the three and nine months ended Sept. 30, 2022, the NSP System received approximately $40 million and $50 million, respectively, of capacity credits. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharingtariffs, or other ~~mechanisms.~~

~~Inflation Reduction Act —~~ ~~In August 2022, the IRA was signed into law.~~

~~Key provisions impacting Xcel Energy include:~~

•~~Extends current PTC and ITC for renewable technologies~~restrictions on solar imports (e.g., ~~wind and solar).~~

•~~Restores full value of the PTC and ITC for qualifying facilities placed in-service after 2021.~~

•~~Creates a PTC for solar, clean hydrogen and nuclear.~~

•~~Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.~~

•~~Allows companies to monetize or sell credits to unrelated parties.~~

Xcel Energy anticipates the IRA will drive approximately $500 million of customer savings over the next 5 years for existing company owned renewable projects, assuming appropriate regulatory mechanisms and development of a market for the sale of credits. The IRA will drive additional customer savings as ~~Xcel Energy adds new renewable projects due to the extension of tax credits and transferability.~~

The IRA is expected to allow Xcel Energy to monetize tax credits more efficiently with the incremental benefits passed through to customers. Transferability provisions apply to eligible tax credits generated starting in 2023 for both new and existing facilities. Xcel Energy anticipates tax credit transferability from existing renewable projects will improve cash from operations by $1.8 billion (2023-2027), assuming constructive regulatory outcomes and the development of a market. Tax credit transferability has been included in our five-year financing plan and rate base projections.

The IRA creates a nuclear PTC beginning in 2024 that may also provide additional customer savings. The annual customer benefit from these PTCs could range from $0 to $200 million, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of the credits.

~~In addition, the IRA created a new corporate AMT. Xcel Energy does not anticipate AMT having a material cash impact based on current estimates and our interpretation of AMT application.~~

~~Winter Storm Uri~~

In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of implementation of the ~~extremely high market prices, Xcel Energy incurred net natural gas, fuel~~Uyghur Forced Labor Protection Act) or disruptions in solar imports from key suppliers could impact project timelines and ~~purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).~~costs.

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New Technology and Government Grants

Hydrogen Hub Grant

In October 2023, the DOE selected the Heartland Hydrogen Hub, including multiple clean hydrogen projects from Xcel Energy, for award negotiations to receive up to $925 million. The Heartland Hydrogen Hub is one of seven selected to receive DOE funding. The hub includes Xcel Energy, Marathon Petroleum Corporation and TC Energy, in collaboration with the University of North Dakota’s Energy & Environmental Resource Center, to produce and use low-carbon hydrogen at commercial scale in Minnesota, Wisconsin, South Dakota, North Dakota and Montana. The hub aims to reduce carbon emissions by more than 1 million metric tons per year. Xcel Energy expects to receive a large portion of the federal award for its projects within the hub, subject to negotiations. In its application, Xcel Energy proposed investing up to $2 billion over a decade for clean hydrogen producing equipment and infrastructure, representing 75% of full program costs for the company’s portion of the hub. Project detailed design will begin after the Heartland Hydrogen Hub finishes award negotiations. Project development will likely continue through 2035.

Form Energy Long Duration Storage Grant

In September 2023, the DOE awarded Xcel Energy a $70 million grant to support our two 10 MW, 100-hour battery pilots with Form Energy. Xcel Energy expects to develop a 10 MW 100-hour-battery storage unit at the Sherco retiring coal plant site in Minnesota and the Comanche retiring coal plant site in Colorado. Combined with grants from Breakthrough Energy’s Catalyst Fund, Xcel Energy has ~~received recovery approval~~secured $90 million to support these pilots, which will reduce the costs of the projects for our customers. Long duration energy storage systems are critical to achieve 100% carbon free generation and strengthen the grid from ~~all~~the variability of ~~our impacted states except~~renewable energy.

Wildfire/Extreme Weather Grant

In October 2023, the DOE awarded Xcel Energy $100 million to support projects to mitigate the threat of wildfires and ensure resiliency of the grid through extreme weather. Xcel Energy plans to match the grant with $140 million of investment. The projects will take a number of steps to boost grid resiliency, including adding fire-resistant coatings to 6,000 wood poles, improving equipment safety features in power lines and electric vehicle chargers in high fire risk conditions, moving high-risk distribution circuits underground, and enhancing vegetation management. They will also build on current programs using emerging technology, such as drones aided by artificial intelligence that inspect power lines for ~~Texas, which~~safety, wind strength testing, satellite identification of trees that pose a risk and modeling software to predict how fires would spread.

JTIQ Grant

In October 2023, the DOE awarded a $464 million grant to Xcel Energy and several other utilities for five JTIQ projects. The projects are part of a collaboration between MISO and SPP that will help to fund the construction of high-voltage transmission lines that improve reliability and resolve constraints in the transmission system for up to 30 gigawatts of new generation. Xcel Energy is ~~pending. A summary~~part of ~~pending and recently approved regulatory requests for Winter Storm Uri cost recovery is listed below.~~two of these project awards.


~~Utility Subsidiary~~	~~Jurisdiction~~	~~Regulatory Status~~Critical Accounting Policies and Estimates
~~NSP-Minnesota~~	~~Minnesota~~	In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period. ~~In May 2022, the ALJs found the Winter Storm Uri fuel costs were prudently incurred and recommended no disallowances.~~ ~~In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance.~~
~~PSCo~~	~~Colorado~~	In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge. In May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs with the exception of an $8 million disallowance.
~~SPS~~	~~Texas~~	~~In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million.~~ In April 2022, interim rates designed to recover $121 million over 30 months were approved. The interim rate recovery does not address the prudence of costs nor the retention of approximately $10 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision. In July 2022, the intervenors filed recommendations in the Fuel Reconciliation proceeding. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins). ~~A recommendation from the ALJ is expected in the fourth quarter of 2022 and a final decision is anticipated in the first quarter of 2023.~~

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 ~~April 2022~~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 ~~the "Good Neighbor" provisions of the~~ Clean Air ~~Act.~~Act Section 111(b) and emission guidelines for existing coal and certain natural gas generation under Clean Air Act Section 111(d). The proposed rules ~~establish an allowance trading program for NOx, potentially impacting~~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 ~~generating~~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 ~~in Minnesota, Texas~~ and ~~Wisconsin. Facilities without NOx controls will have~~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 ~~secure additional allowances, install NOx controls, or develop a strategy~~the CCR Rule requirements, including groundwater monitoring, corrective action, closure, and post-closure care requirements, among other requirements, with several of ~~operations that utilizes~~ the ~~existing allowance allocations.~~ deadlines accelerated.

The EPA has ~~indicated~~committed to a May 2024 effective date for those new rules. It is also anticipated that ~~it intends for~~ the ~~rule to be final by~~EPA may issue other CCR proposed rules in 2023 that further expand the ~~end of 2022 with initial applicability for 2023. While the financial impacts~~scope of the ~~proposed regulation~~CCR Rule. Until final rules are ~~uncertain,~~issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy ~~anticipates~~believes that ~~costs will~~the cost of these initiatives would be recoverable through ~~regulatory mechanisms.~~rates based on prior state commission practices.

~~CERCLA~~

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, specifically perfluorooctanoic acid and perfluorooctanesulfonic acid. This~~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 wherever PFAS are found~~cleanup. Xcel Energy is monitoring changes to ~~be present.~~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 ~~regulation may have~~regulations were submitted on ~~electric and gas utilities~~May 30, 2023. The impact of these proposed regulations is ~~currently uncertain.~~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 offor a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

~~See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.~~

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 ~~under~~on the contracts underlying our derivatives, the contracts expose us to ~~some~~ 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 and Xcel Energy’s ability to earn a return on short-term investments.~~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-~~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 Sept. 30, ~~2022:~~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)
$ (8) $ (11) $ (6) $ (3) $ (28)
NSP- Minnesota (b)
6 4 (1) (2) 7
PSCo (a)
17 7 3 1 28
PSCo (b)
(50) (21) 1 — (70)
$ (35) $ (21) $ (3) $ (4) $ (63)


	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)		(4)		(1)		(11)
PSCo (a)	2		1		3		—		6
PSCo (b)	(14)		6		—		—		(8)
	$	(14)	$	(3)	$	(5)	$	(1)	$	(23)

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		Options Maturity											Options Maturity
(Millions of Dollars)	(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	NSP-Minnesota (b)	$	1	$	—	$	—	$	14	$	15	NSP-Minnesota (b)	$	—	$	—	$	6	$	10	$	16
PSCo (b)	PSCo (b)	28		7		—		—		35		PSCo (b)	8		—		—		—		8
		$	29	$	7	$	—	$	14	$	50		$	8	$	—	$	6	$	10	$	24

(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 nine months ended Sept. 30:


(Millions of Dollars)	(Millions of Dollars)	2022		2021		(Millions of Dollars)	2023		2022
Fair value of commodity trading net contracts outstanding at Jan. 1	Fair value of commodity trading net contracts outstanding at Jan. 1	$	(33)	$	(54)	Fair value of commodity trading net contracts outstanding at Jan. 1	$	(33)	$	(33)
Contracts realized or settled during the period	Contracts realized or settled during the period	(11)		(35)		Contracts realized or settled during the period	1		(11)
Commodity trading contract additions and changes during the period	Commodity trading contract additions and changes during the period	31		72		Commodity trading contract additions and changes during the period	33		31
Fair value of commodity trading net contracts outstanding at Sept. 30	Fair value of commodity trading net contracts outstanding at Sept. 30	$	(13)	$	(17)	Fair value of commodity trading net contracts outstanding at Sept. 30	$	1	$	(13)

~~At Sept. 30, 2022, a~~A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts ~~through the forward curve~~ would ~~increase pre-tax~~have likewise increased and decreased pretax income from continuing operations, by approximately $4 million at Sept. 30, 2023, and approximately $9 million ~~whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $9 million. At~~at Sept. 30, 2021, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $23 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $23 million.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 ~~that have been entered into, but not closed,~~ 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 ~~purchase,~~purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:


(Millions of Dollars)	(Millions of Dollars)	Three Months Ended Sept. 30		Average		High		Low		(Millions of Dollars)	Three Months Ended Sept. 30		Average		High		Low
2023										2023	$	0.6	$	1.0	$	1.8	$	0.5
2022	2022	$	0.9	$	1.7	$	3.0	$	0.8	2022	0.9		1.7		3.0		0.8
2021		1.9		1.5		2.2		0.9

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Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023, 2024 and ~~has its 2022 and 2023~~2025 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. ~~We will continue to monitor the evolving situation in Ukraine and its global impacts and will take necessary actions to ensure a secure supply of enriched nuclear material.~~ NSP-Minnesota is scheduled to take delivery of approximately ~~30%~~28% 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 such as swaps, caps, collars and put or call options.~~derivatives.

~~At Sept. 30, 2022 and 2021, a 100-basis-point~~A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact ~~pre-tax~~pretax interest expense annually by approximately $2 million and $3 million in Sept. 30, 2023 and ~~$18 million,~~2022, respectively.

~~See Note 8 to the consolidated financial statements for a discussion of Xcel Energy’s interest rate derivatives.~~

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

~~Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.~~ 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.

~~Changes~~The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan ~~assets impact the value of~~assets. Xcel Energy’s ongoing pension and postretirement ~~plan assets and/or benefit costs.~~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 Sept. 30, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $32 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $28 million. At Sept. 30, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $71 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $57 million. At Sept. 30, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $73 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $43 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~~Fair Value Measurements

~~Xcel Energy uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk.~~ Derivative contracts, with the exception of those designated as normal ~~purchase-normal sale contracts,~~purchases and normal sales, are reported at fair value.

~~The Company’s~~ Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.

See Note 8 to the consolidated financial statements for further ~~discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.~~

~~Commodity Derivatives~~ — Xcel Energy monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Sept. 30, 2022.

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Sept. 30, 2022.

information.

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

Cash Flows

Operating Cash Flows


(Millions of Dollars)	Nine Months Ended Sept. 30
Cash provided by operating activities — ~~2021~~2022	$	~~1,579~~3,167

Components of change — ~~2022~~2023 vs. ~~2021~~2022
Higher net income	755
Non-cash transactions	~~159~~ (91)
Changes in working capital	~~(79)~~812
Changes in net regulatory and other assets and liabilities	~~1,433~~460
Cash provided by operating activities — ~~2022~~2023	$	~~3,167~~4,353

Net cash provided by operating activities increased ~~$1,588~~$1,186 million for the nine months ended Sept. 30, ~~2022~~2023 compared with the prior year. The increase was ~~primarily~~largely due to ~~the~~continued collections of prior year deferred net natural gas, fuel and purchased energy costs, ~~related to Winter Storm Uri (incurred/deferred) in~~as well as the ~~first quarter~~impact of ~~2021.~~decreased natural gas prices on accounts payable and receivables.

Investing Cash Flows


(Millions of Dollars)	Nine Months Ended Sept. 30
Cash used in investing activities — ~~2021~~2022	$	~~(3,065)~~(3,321)

Components of change — ~~2022~~2023 vs. ~~2021~~2022
Increased capital expenditures	~~(293)~~(915)

Other investing activities	37 (56)
Cash used in investing activities — ~~2022~~2023	$	~~(3,321)~~(4,292)

Net cash used in investing activities increased ~~$256~~$971 million for the nine months ended Sept. 30, ~~2022~~2023 compared with the prior year. The increase in capital expenditures was largely due to ~~timing and normal/planned~~continued system expansion.

Financing Cash Flows


(Millions of Dollars)	Nine Months Ended Sept. 30
Cash provided by financing activities — ~~2021~~2022	$	~~1,988~~105

Components of change — ~~2022~~2023 vs. ~~2021~~2022
~~Higher~~Lower net short-term ~~debt~~ repayments	~~(2,010)~~34
Higher long-term debt issuances, net of repayments	43416
~~Higher~~Lower proceeds from issuance of common stock	~~143~~ (73)

Other financing activities	~~(59)~~(60)
Cash provided by financing activities — ~~2022~~2023	$	~~105~~422

Net cash provided by financing activities ~~decreased $1,883~~increased $317 million for the nine months ended Sept. 30, ~~2022~~2023 compared with the prior year. The ~~decrease~~increase was ~~primarily~~largely related to the amount/timing of debt issuances and ~~repayments associated with Winter Storm Uri.~~repayments.

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Capital Requirements

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

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

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

•In ~~2021,~~2022, contributions of ~~$131~~$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 ~~Oct. 25, 2022,~~October 23, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity		(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity
Xcel Energy Inc.	Xcel Energy Inc.	$	1,500	$	129	$	1,371	$	1	$	1,372	Xcel Energy Inc.	$	1,500	$	—	$	1,500	$	19	$	1,519
PSCo	PSCo	700		264		436		3		439		PSCo	700		239		461		3		464
NSP-Minnesota	NSP-Minnesota	700		55		645		4		649		NSP-Minnesota	700		15		685		8		693
SPS	SPS	500		67		433		1		434		SPS	500		—		500		18		518
NSP-Wisconsin	NSP-Wisconsin	150		—		150		3		153		NSP-Wisconsin	150		—		150		8		158
Total	Total	$	3,550	$	515	$	3,035	$	12	$	3,047	Total	$	3,550	$	254	$	3,296	$	56	$	3,352

(a)Credit facilities expire in September 2027.

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

~~Bilateral Credit Agreement~~

~~In April 2022, NSP-Minnesota’s uncommitted $75 million 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 Sept. 30, 2022, NSP-Minnesota had $50 million of outstanding letters of credit under the $75 million bilateral credit agreement.~~

Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. ~~The~~As of Sept. 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.

~~Table of Contents~~

~~Short-term debt outstanding for Xcel Energy was as follows:~~

(Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2022 Year Ended Dec. 31, 2021
Borrowing limit $ 3,550 $ 3,100
Amount outstanding at period end 158 1,005
Average amount outstanding 187 1,399
Maximum amount outstanding 329 2,054
Weighted average interest rate, computed on a daily basis 2.51 % 0.57 %
Weighted average interest rate at period end 3.40 0.31

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.

Capital Expenditures — Base capital expenditures and incremental capital forecasts for Xcel Energy for ~~2023~~2024 through ~~2027~~2028 are as follows:


		Base Capital Forecast (Millions of Dollars)													Base Capital Forecast (Millions of Dollars)
By Regulated Utility	By Regulated Utility	2023		2024		2025		2026		2027		2023 - 2027 Total		By Regulated Utility	2024		2025		2026		2027		2028		Total
PSCo	PSCo	$	2,140	$	2,440	$	2,550	$	1,980	$	2,190	$	11,300	PSCo	$	2,580	$	2,940	$	3,030	$	3,070	$	2,640	$	14,260
NSP-Minnesota	NSP-Minnesota	2,000		2,400		2,530		2,200		2,580		11,710		NSP-Minnesota	2,660		2,970		2,380		2,500		2,180		12,690
SPS	SPS	710		780		720		770		900		3,880		SPS	910		780		660		870		830		4,050
NSP-Wisconsin	NSP-Wisconsin	540		570		500		450		540		2,600		NSP-Wisconsin	570		600		570		600		650		2,990
Other (a)	Other (a)	10		10		(30)		10		10		10		Other (a)	(20)		—		10		10		10		10
Total base capital expenditures	Total base capital expenditures	$	5,400	$	6,200	$	6,270	$	5,410	$	6,220	$	29,500	Total base capital expenditures	$	6,700	$	7,290	$	6,650	$	7,050	$	6,310	$	34,000

(a)Other category includes intercompany transfers for safe harbor wind turbines.


		Base Capital Forecast (Millions of Dollars)													Base Capital Forecast (Millions of Dollars)
By Function	By Function	2023		2024		2025		2026		2027		2023 - 2027 Total		By Function	2024		2025		2026		2027		2028		Total
Electric transmission														Electric transmission	$	1,880	$	2,150	$	2,500	$	2,840	$	2,080	$	11,450
Electric distribution	Electric distribution	$	1,610	$	1,790	$	1,680	$	2,000	$	2,450	$	9,530	Electric distribution	1,720		1,840		2,030		2,200		2,410		10,200
Electric transmission		1,280		1,650		1,890		1,690		1,900		8,410
Electric generation	Electric generation	710		910		900		560		650		3,730		Electric generation	930		1,160		780		740		600		4,210
Natural gas	Natural gas	740		730		760		650		680		3,560		Natural gas	740		680		630		620		570		3,240
Renewables														Renewables	670		740		40		20		20		1,490
Other	Other	780		840		570		510		540		3,240		Other	760		720		670		630		630		3,410
Renewables		280		280		470		—		—		1,030
Total base capital expenditures	Total base capital expenditures	$	5,400	$	6,200	$	6,270	$	5,410	$	6,220	$	29,500	Total base capital expenditures	$	6,700	$	7,290	$	6,650	$	7,050	$	6,310	$	34,000

The base plan does not include any potential renewable generation assets ~~approved in our Minnesota~~associated with the Colorado recommended Preferred Plan (pending CPUC approval) and ~~Colorado resource plans or additional transmission capital needed to integrate new~~potential renewable generation additions ~~in Colorado, beyond~~at the ~~Pathway project. We expect further clarification in the second half of 2023 after the commissions rule on the recommended resource plan portfolios,~~NSP System and SPS, which could result in ~~incremental~~additional capital expenditures of approximately $2$10 billion. Xcel Energy generally expects to ~~$4 billion (assuming 50% ownership of renewable projects).~~fund additional capital investment with approximately 40% equity and 60% debt.

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.

Table of Contents

Financing for Capital Expenditures through ~~2027~~2028 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Current estimated financing plans of Xcel Energy for ~~2023~~2024 through ~~2027~~2028 (includes the impact ~~of approximately $1.8 billion~~ of tax credit transferability):


(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)	$	~~20,540~~20,520
New debt (b)	~~8,210~~10,980
Equity through the DRIP and benefit program	~~425~~500
Other equity	~~325~~2,000
Base capital expenditures ~~2023-2027~~2024-2028	$	~~29,500~~34,000

Maturing ~~Debt~~debt	$	~~3,800~~3,780

(a)Net of dividends and pension funding.

(b)Reflects a combination of short and long-term debt; net of ~~refinancing~~.refinancing.

~~2022~~2023 Planned Financing Activity — During ~~2022,~~2023, Xcel Energy plans to issue approximately ~~$75 to $80~~$85 million of equity through the DRIP and benefit programs. In ~~2022,~~addition, we issued approximately ~~$150~~$62 million of equity ~~has been issued through an at-the-market program.~~under the ATM program in 2023. Xcel Energy and its utility subsidiaries issued the following long-term debt:

Issuer

Security

Amount

Tenor

Coupon

Issuer

Security

Amount

Status

Tenor

Coupon

Xcel Energy

Unsecured Senior Notes

700

million

10 Year

4.60%

Xcel Energy

Unsecured Senior Notes

800

million

Completed

10 Year

5.45%

PSCo

First Mortgage Bonds

300

million

10 Year

4.10%

PSCo

First Mortgage Bonds

850

million

Completed

30 Year

5.25

PSCo

First Mortgage Bonds

400

million

30 Year

4.50%

SPS

First Mortgage Bonds

200

million

30 Year

5.15%

NSP-Minnesota

First Mortgage Bonds

500

million

30 Year

4.50%

NSP-Minnesota

First Mortgage Bonds

800

million

Completed

30 Year

5.10

NSP-Wisconsin

First Mortgage Bonds

100

million

30 Year

4.86%

NSP-Wisconsin

First Mortgage Bonds

125

million

Completed

30 Year

5.30

SPS

First Mortgage Bonds

100

million

Completed

30 Year

6.00

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.

~~Table of Contents~~

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

Xcel Energy ~~2022~~2023 Earnings Guidance — Xcel Energy’s ~~2022 GAAP and~~2023 ongoing earnings guidance is a narrowed range of ~~$3.14~~$3.32 to ~~$3.19~~$3.37 per share, from the original guidance of $3.30 to $3.40 per share.(a)

Key assumptions as compared with ~~2021~~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 ~~~2%~~~1% to 2%.

•Weather-normalized retail firm natural gas sales are projected to increase ~1%.

•Capital rider revenue is projected to ~~be relatively flat~~increase $40 million to $50 million (net of PTCs). ~~The reduction in capital rider revenue is due to changes in expected PTC levels and is largely earnings neutral.~~

•O&M expenses are projected to ~~increase approximately 4%~~decline ~1% to 2%.

•Depreciation expense is projected to increase approximately ~~$295~~$25 million to ~~$305~~$35 million.

•Property taxes are projected to ~~increase approximately $35~~decrease $30 million to ~~$45~~$35 million.

•Interest expense (net of AFUDC - debt) is projected to increase ~~$100~~$90 million to ~~$110~~$100 million.

•AFUDC - equity is projected to ~~be relatively flat.~~increase $10 million to $15 million.

•ETR is projected to be ~~~(7%~~~(9%) to ~~(9%~~(11%). The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral.

Xcel Energy ~~2023~~2024 Earnings Guidance — Xcel Energy’s ~~2023 GAAP and~~2024 ongoing earnings guidance is a range of ~~$3.30~~$3.50 to ~~$3.40~~$3.60 per share.(a)

Key assumptions as compared with ~~2022~~2023 projected levels unless noted:

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

•Normal weather patterns for the year.

•Weather-normalized retail electric sales are projected to increase ~~~1%~~2% to 3%.

•Weather-normalized retail firm natural gas sales are projected to ~~be relatively flat.~~increase ~1%.

•Capital rider revenue is projected to increase ~~$70~~$35 million to ~~$80~~$45 million (net of PTCs).

•O&M expenses are projected to ~~be relatively flat.~~increase 1% to 2%.

•Depreciation expense is projected to increase approximately ~~$140~~$250 million to ~~$150~~$260 million.

•Property taxes are projected to increase ~~approximately $35~~$40 million to ~~$45~~$50 million.

•Interest expense (net of AFUDC - debt) is projected to increase ~~$110~~$115 million to ~~$120~~$125 million.

•AFUDC - equity is projected to increase $0$40 million to ~~$10~~$50 million.

•ETR is projected to be ~~~(5%~~~(4%) to ~~(7%~~(6%). The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral.

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

Table of Contents

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

• Deliver long-term annual EPS growth of 5% to 7% based off of a ~~2022~~2023 base of ~~$3.15~~$3.35 per share, which represents the mid-point of the original ~~2022~~2023 guidance range of ~~$3.10~~$3.30 to ~~$3.20~~$3.40 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 AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, ~~2021~~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 Sept. 30, ~~2022,~~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.

~~Table of Contents~~

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, ~~2021,~~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 ended Sept. 30, ~~2022~~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 Sept. 30, 2023.

On October 25, 2023, the Governance, Compensation and Nominating Committee of the Board of Directors approved and granted a $9,000,000 restricted stock unit award for Robert C. Frenzel, Chairman, President and Chief Executive Officer, to incentivize his consistent leadership and continuity through Xcel Energy’s clean energy transition. The award was made under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan pursuant to the form of award agreement in Exhibit 10.26 to Xcel Energy’s Form 10-K for the year ended December 31, 2022, which is incorporated herein by reference. The award consisted of 152,336 restricted stock units that will vest 33% on February 28, 2027 and 67% on February 29, 2028 if Mr. Frenzel continues to be employed by Xcel Energy as of such dates.

Table of Contents


ITEM 6 — EXHIBITS


*			Indicates incorporation by reference


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012	Xcel Energy Inc. Form 8-K dated May 16, 2012	3.01
3.02*	Bylaws of Xcel Energy Inc., as Amended and Restated on ~~April 3, 2020~~August 23, 2023	Xcel Energy Inc Form 8-K dated ~~April 3, 2020~~August 23, 2023	~~3.01~~3.02
4.01*	Supplemental Indenture No. 17, dated as of ~~July~~August 3, 2023, by and between Xcel Energy Inc. and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee, creating $800,000,000 aggregate principal amount of 5.45% Senior Notes, Series due August 15, ~~2022~~2033	Xcel Energy Inc Form 8-K dated August 3, 2023	4.01
4.02*	Supplemental Indenture No. 10 dated as of August 21, 2023 between ~~Northern States Power Company~~SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as ~~successor~~ Trustee, creating ~~4.86%~~6.00% First Mortgage Bonds, Series No. 10 due ~~September 15, 2052~~2053	~~NSP-Wisconsin~~SPS Form 8-K dated ~~July 15, 2022~~August 21, 2023	4.01
~~10.01~~*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank Ltd. and Wells Fargo Bank, National Association, as Documentation Agents	~~Xcel Energy Inc. Form 8-K dated September 19, 2022~~	~~99.01~~
~~10.02~~*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Northern States Power Company, a Minnesota corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association as Documentation Agents	~~Xcel Energy Inc. Form 8-K dated September 19, 2022~~	~~99.02~~
~~10.03~~*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Public Service Company of Colorado, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents	~~Xcel Energy Inc. Form 8-K dated September 19, 2022~~	~~99.03~~
~~10.04~~*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Southwestern Public Service Company, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents	~~Xcel Energy Inc. Form 8-K dated September 19, 2022~~	~~99.04~~
~~10.05~~*	Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, among Northern States Power Company, a Wisconsin corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents	~~Xcel Energy Inc. Form 8-K dated September 19, 2022~~	~~99.05~~
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002.~~2002
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002.~~2002
32.01	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002.~~2002
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL ~~document.~~document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

3435

Table of Contents

SIGNATURES

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


		XCEL ENERGY INC.

10/27/~~2022~~23	By:	/s/ BRIAN J. VAN ABEL
		Brian J. Van Abel
		Executive Vice President, Chief Financial Officer
		(~~Duly Authorized~~Principal Accounting Officer and Principal Financial Officer)

3536


Recommended Position	DOC		XLI		CUB	JSC
ROE	9.25	%	9.17	%	8.80-9.00 %	9.06	%
Equity	52.5	%	N/A		N/A	N/A