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, ~~2021~~2022


☐			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~~Name of ~~registrant~~Registrant as ~~specified~~Specified in its ~~charter)~~Charter)

Minnesota

41-0448030

(State or ~~other jurisdiction~~Other Jurisdiction of ~~incorporation~~Incorporation or ~~organization)~~Organization)

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

414 Nicollet Mall

Minneapolis

Minnesota

55401

(Address of ~~principal executive offices)~~
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)~~Telephone Number, Including Area Code)

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. ~~26, 2021~~25, 2022
Common Stock, $2.50 par value						~~538,675,570~~547,248,496 shares

TABLE OF CONTENTS


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	45
	Consolidated Statements of Income	45
	Consolidated Statements of Comprehensive Income	56
	Consolidated Statements of Cash Flows	67
	Consolidated Balance Sheets	78
	Consolidated Statements of Common Stockholders’ Equity	89
	Notes to Consolidated Financial Statements	910
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2221
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	3533
Item 4 —	Controls and Procedures	3533

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	3533
Item 1A —	Risk Factors	3534
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	3534
Item 6 —	Exhibits	3534

SIGNATURES		3735

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available onin various filings with the ~~Securities and Exchange Commission.~~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
~~COEO~~			~~Colorado Energy Office~~
CPUC			Colorado Public Utilities Commission
D.C. Circuit			United States Court of Appeals for the District of Columbia Circuit
DOC			Minnesota Department of Commerce
EPA			United States Environmental Protection Agency
~~ERCOT~~			~~Electric Reliability Council of Texas~~
FERC			Federal Energy Regulatory Commission

MPUC			Minnesota Public Utilities Commission

NDPSC			North Dakota Public Service Commission
~~NMPRC~~			~~New Mexico Public Regulation Commission~~
NRC			Nuclear Regulatory Commission
OAG			Minnesota Office of Attorney General
~~PSCW~~			~~Public Service Commission of Wisconsin~~
PUCT			Public Utility Commission of Texas

SEC			Securities and Exchange Commission
~~UCA~~			~~Colorado Office of the Utility Consumer Advocate~~


Electric, Purchased Gas and Resource Adjustment Clauses
~~DSM~~GCA			~~Demand side management~~
~~FCA~~			~~Fuel clause~~Gas cost adjustment
GUIC			Gas utility infrastructure cost rider
~~PSIA~~			~~Pipeline System Integrity Adjustment~~
RES			Renewable energy standard
TCR			Transmission cost recovery adjustment


Other
AFUDC			Allowance for funds used during construction
ALJ			Administrative Law Judge
~~ASC~~AMT			~~FASB Accounting Standards Codification~~Alternative minimum tax
ATM			At-the-market
C&I			Commercial and Industrial
CCR			Coal combustion residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD			Cooling degree-days
CEO			Chief executive officer
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFO			Chief financial officer


~~COVID-19~~CORE			~~Novel coronavirus~~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
~~EIP~~			~~Energy Impact Partners~~
EPS			Earnings per share
ETR			Effective tax rate
~~FASB~~			~~Financial Accounting Standards Board~~
FTR			Financial transmission right
GAAP			United States generally accepted accounting principles
~~GCA~~			~~Gas cost adjustment~~
GE			General Electric Company
HDD			Heating degree-days
IPP			Independent power producing entity
~~KEPCO~~IRA			~~Korea Electric Power Corporation~~Inflation Reduction Act
ITC			Investment Tax Credit
JSC			Just Solar Coalition
LLC			Limited liability company
LP&L			Lubbock Power and Light
~~MDL~~			~~Multi district litigation~~
~~MEC~~			~~Mankato Energy Center~~
MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator, Inc.
NAV			Net asset value
~~NOL~~			~~Net operating loss~~
NOPR			Notice of Proposed Rulemaking
NOx			Nitrogen Oxides
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff


PFAS			Per- and ~~PolyFluoroAlkyl~~PolyFluroroAlkyl Substances
PIM			Performance Incentive Mechanism
PPA			Power purchase agreement
PTC			Production tax credit
ROE			Return on equity
RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.
THI			Temperature-humidity index
TOs			Transmission owners
UCA			Colorado Office of the Utility Consumer Advocate
VaR			Value at Risk
~~VIE~~WACC			~~Variable interest entity~~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 ~~the 2021~~those relating to 2022 and ~~2022~~2023 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2020~~2021 and subsequent ~~filing~~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;~~pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; operational safety, including our nuclear generation ~~facilities;~~facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs ~~changes in regulation~~ 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; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; ~~and~~ costs of potential regulatory ~~penalties.~~penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; 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
		2021		2020		2021		2020			2022		2021		2022		2021
Operating revenues	Operating revenues									Operating revenues
Electric	Electric	$	3,176	$	2,941	$	8,643	$	7,430	Electric	$	3,699	$	3,176	$	9,255	$	8,643
Natural gas	Natural gas	268		219		1,364		1,082		Natural gas	357		268		1,923		1,364
Other	Other	23		22		69		67		Other	26		23		79		69
Total operating revenues	Total operating revenues	3,467		3,182		10,076		8,579		Total operating revenues	4,082		3,467		11,257		10,076

Operating expenses	Operating expenses									Operating expenses
Electric fuel and purchased power	Electric fuel and purchased power	1,210		981		3,643		2,611		Electric fuel and purchased power	1,497		1,210		3,772		3,643
Cost of natural gas sold and transported	Cost of natural gas sold and transported	86		54		603		425		Cost of natural gas sold and transported	173		86		1,134		603
Cost of sales — other	Cost of sales — other	11		11		28		28		Cost of sales — other	11		11		32		28
Operating and maintenance expenses		568		579		1,752		1,708
O&M expenses										O&M expenses	611		568		1,827		1,752
Conservation and demand side management expenses	Conservation and demand side management expenses	78		73		222		215		Conservation and demand side management expenses	86		78		259		222
Depreciation and amortization	Depreciation and amortization	537		513		1,586		1,449		Depreciation and amortization	607		537		1,807		1,586
Taxes (other than income taxes)	Taxes (other than income taxes)	152		158		472		453		Taxes (other than income taxes)	173		152		523		472
Total operating expenses	Total operating expenses	2,642		2,369		8,306		6,889		Total operating expenses	3,158		2,642		9,354		8,306

Operating income	Operating income	825		813		1,770		1,690		Operating income	924		825		1,903		1,770

Other (expense) income, net	Other (expense) income, net	(3)		1		5		(6)		Other (expense) income, net	(15)		(3)		(20)		5
Earnings from equity method investments	Earnings from equity method investments	13		12		47		29		Earnings from equity method investments	1		13		27		47
Allowance for funds used during construction — equity	Allowance for funds used during construction — equity	21		30		53		91		Allowance for funds used during construction — equity	20		21		53		53

Interest charges and financing costs	Interest charges and financing costs									Interest charges and financing costs
Interest charges — includes other financing costs of $7, $7, $22 and $21, respectively		211		221		628		628
Interest charges — includes other financing costs of $8, $7, $24 and $22, respectively										Interest charges — includes other financing costs of $8, $7, $24 and $22, respectively	244		211		705		628
Allowance for funds used during construction — debt	Allowance for funds used during construction — debt	(7)		(11)		(18)		(33)		Allowance for funds used during construction — debt	(7)		(7)		(19)		(18)
Total interest charges and financing costs	Total interest charges and financing costs	204		210		610		595		Total interest charges and financing costs	237		204		686		610

Income before income taxes	Income before income taxes	652		646		1,265		1,209		Income before income taxes	693		652		1,277		1,265
Income tax expense (benefit)	Income tax expense (benefit)	43		43		(17)		24		Income tax expense (benefit)	44		43		(80)		(17)
Net income	Net income	$	609	$	603	$	1,282	$	1,185	Net income	$	649	$	609	$	1,357	$	1,282

Weighted average common shares outstanding:	Weighted average common shares outstanding:									Weighted average common shares outstanding:
Basic	Basic	539		526		539		526		Basic	548		539		546		539
Diluted	Diluted	539		528		539		527		Diluted	548		539		546		539

Earnings per average common share:	Earnings per average common share:									Earnings per average common share:
Basic	Basic	$	1.13	$	1.15	$	2.38	$	2.25	Basic	$	1.19	$	1.13	$	2.48	$	2.38
Diluted	Diluted	1.13		1.14		2.38		2.25		Diluted	1.18		1.13		2.48		2.38

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
		2021		2020		2021		2020			2022		2021		2022		2021
Net income	Net income	$	609	$	603	$	1,282	$	1,185	Net income	$	649	$	609	$	1,357	$	1,282
Other comprehensive income (loss)
Other comprehensive income										Other comprehensive income
Pension and retiree medical benefits:	Pension and retiree medical benefits:									Pension and retiree medical benefits:

Reclassifications of loss to net income, net of tax of $1, $—, $2 and $1, respectively		4		1		5		4
Net pension and retiree medical losses arising during the period, net of tax of $4, $—, $4 and $—, respectively										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										Reclassifications of loss to net income, net of tax of $—, $1, $1 and $2, respectively	1		4		2		5
Derivative instruments:	Derivative instruments:									Derivative instruments:
Net fair value increase (decrease), net of tax of $1, $—, $1 and $(3), respectively		3		—		4		(10)
Net fair value increase, net of tax of $—, $1, $6 and $1, respectively										Net fair value increase, net of tax of $—, $1, $6 and $1, respectively	—		3		15		4
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	2		1		6		4		Reclassification of losses to net income, net of tax of $—, $—, $1 and $1, respectively	1		2		4		6

Total other comprehensive income (loss)		9		2		15		(2)
Total other comprehensive income										Total other comprehensive income	12		9		32		15
Total comprehensive income	Total comprehensive income	$	618	$	605	$	1,297	$	1,183	Total comprehensive income	$	661	$	618	$	1,389	$	1,297

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
		2021		2020			2022		2021
Operating activities	Operating activities					Operating activities
Net income	Net income	$	1,282	$	1,185	Net income	$	1,357	$	1,282
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	1,597		1,459		Depreciation and amortization	1,821		1,597
Nuclear fuel amortization	Nuclear fuel amortization	86		94		Nuclear fuel amortization	91		86
Deferred income taxes	Deferred income taxes	(9)		45		Deferred income taxes	(85)		(9)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(53)		(91)		Allowance for equity funds used during construction	(53)		(53)
Earnings from equity method investments	Earnings from equity method investments	(47)		(29)		Earnings from equity method investments	(27)		(47)
Dividends from equity method investments	Dividends from equity method investments	31		32		Dividends from equity method investments	30		31
Provision for bad debts	Provision for bad debts	53		39		Provision for bad debts	41		53
Share-based compensation expense	Share-based compensation expense	20		60		Share-based compensation expense	19		20
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	(152)		(108)		Accounts receivable	(221)		(152)
Accrued unbilled revenues	Accrued unbilled revenues	58		124		Accrued unbilled revenues	69		58
Inventories	Inventories	(82)		(37)		Inventories	(272)		(82)
Other current assets	Other current assets	8		(68)		Other current assets	13		8
Accounts payable	Accounts payable	61		(97)		Accounts payable	152		61
Net regulatory assets and liabilities	Net regulatory assets and liabilities	(997)		(139)		Net regulatory assets and liabilities	239		(997)
Other current liabilities	Other current liabilities	(22)		(54)		Other current liabilities	51		(22)
Pension and other employee benefit obligations	Pension and other employee benefit obligations	(131)		(138)		Pension and other employee benefit obligations	(59)		(131)
Other, net	Other, net	(124)		(103)		Other, net	1		(124)
Net cash provided by operating activities	Net cash provided by operating activities	1,579		2,174		Net cash provided by operating activities	3,167		1,579

Investing activities	Investing activities					Investing activities
Capital/construction expenditures	Capital/construction expenditures	(3,032)		(3,681)		Capital/construction expenditures	(3,325)		(3,032)
Sale of MEC		—		684
Purchase of investment securities	Purchase of investment securities	(540)		(1,275)		Purchase of investment securities	(1,055)		(540)
Proceeds from the sale of investment securities	Proceeds from the sale of investment securities	531		1,260		Proceeds from the sale of investment securities	1,029		531
Other, net	Other, net	(24)		(9)		Other, net	30		(24)
Net cash used in investing activities	Net cash used in investing activities	(3,065)		(3,021)		Net cash used in investing activities	(3,321)		(3,065)

Financing activities	Financing activities					Financing activities
Proceeds from (repayments of) short-term borrowings, net		1,163		(95)
(Repayments of) proceeds from short-term borrowings, net						(Repayments of) proceeds from short-term borrowings, net	(847)		1,163
Proceeds from issuances of long-term debt	Proceeds from issuances of long-term debt	1,920		2,940		Proceeds from issuances of long-term debt	2,164		1,920
Repayments of long-term debt, including reacquisition premiums	Repayments of long-term debt, including reacquisition premiums	(399)		(701)		Repayments of long-term debt, including reacquisition premiums	(600)		(399)
Proceeds from issuance of common stock	Proceeds from issuance of common stock	13		5		Proceeds from issuance of common stock	156		13
Dividends paid	Dividends paid	(698)		(638)		Dividends paid	(754)		(698)
Other, net	Other, net	(11)		(27)		Other, net	(14)		(11)
Net cash provided by financing activities	Net cash provided by financing activities	1,988		1,484		Net cash provided by financing activities	105		1,988

Net change in cash, cash equivalents and restricted cash	Net change in cash, cash equivalents and restricted cash	502		637		Net change in cash, cash equivalents and restricted cash	(49)		502
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	129		248		Cash, cash equivalents and restricted cash at beginning of period	166		129
Cash, cash equivalents and restricted cash at end of period	Cash, cash equivalents and restricted cash at end of period	$	631	$	885	Cash, cash equivalents and restricted cash at end of period	$	117	$	631

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)	$	(592)	$	(582)	Cash paid for interest (net of amounts capitalized)	$	(628)	$	(592)
Cash paid for income taxes, net	Cash paid for income taxes, net	(6)		(17)		Cash paid for income taxes, net	(16)		(6)

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	$	476	$	933	Accrued property, plant and equipment additions	$	393	$	476
Inventory transfers to property, plant and equipment	Inventory transfers to property, plant and equipment	87		250		Inventory transfers to property, plant and equipment	34		87
Operating lease right-of-use assets	Operating lease right-of-use assets	4		361		Operating lease right-of-use assets	17		4
Allowance for equity funds used during construction	Allowance for equity funds used during construction	53		91		Allowance for equity funds used during construction	53		53
Issuance of common stock for reinvested dividends and/or equity awards	Issuance of common stock for reinvested dividends and/or equity awards	26		51		Issuance of common stock for reinvested dividends and/or equity awards	40		26

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, 2021		Dec. 31, 2020			Sept. 30, 2022		Dec. 31, 2021
Assets	Assets					Assets
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	631	$	129	Cash and cash equivalents	$	117	$	166
Accounts receivable, net	Accounts receivable, net	1,022		916		Accounts receivable, net	1,196		1,018
Accrued unbilled revenues	Accrued unbilled revenues	656		714		Accrued unbilled revenues	793		862
Inventories	Inventories	587		535		Inventories	870		631
Regulatory assets	Regulatory assets	1,073		640		Regulatory assets	1,275		1,106
Derivative instruments	Derivative instruments	228		49		Derivative instruments	456		123
Prepaid taxes	Prepaid taxes	55		42		Prepaid taxes	54		44
Prepayments and other	Prepayments and other	235		250		Prepayments and other	329		289
Total current assets	Total current assets	4,487		3,275		Total current assets	5,090		4,239

Property, plant and equipment, net	Property, plant and equipment, net	44,730		42,950		Property, plant and equipment, net	47,287		45,457

Other assets	Other assets					Other assets
Nuclear decommissioning fund and other investments	Nuclear decommissioning fund and other investments	3,446		3,096		Nuclear decommissioning fund and other investments	3,083		3,628
Regulatory assets	Regulatory assets	3,101		2,737		Regulatory assets	2,850		2,738
Derivative instruments	Derivative instruments	72		30		Derivative instruments	90		67
Operating lease right-of-use assets	Operating lease right-of-use assets	1,342		1,490		Operating lease right-of-use assets	1,155		1,291
Other	Other	339		379		Other	420		431
Total other assets	Total other assets	8,300		7,732		Total other assets	7,598		8,155
Total assets	Total assets	$	57,517	$	53,957	Total assets	$	59,975	$	57,851

Liabilities and Equity	Liabilities and Equity					Liabilities and Equity
Current liabilities	Current liabilities					Current liabilities
Current portion of long-term debt	Current portion of long-term debt	$	621	$	421	Current portion of long-term debt	$	651	$	601
Short-term debt	Short-term debt	1,747		584		Short-term debt	158		1,005
Accounts payable	Accounts payable	1,319		1,237		Accounts payable	1,586		1,409
Regulatory liabilities	Regulatory liabilities	338		311		Regulatory liabilities	596		271
Taxes accrued	Taxes accrued	553		578		Taxes accrued	545		569
Accrued interest	Accrued interest	206		203		Accrued interest	244		209
Dividends payable	Dividends payable	246		231		Dividends payable	267		249
Derivative instruments	Derivative instruments	76		53		Derivative instruments	100		69
Operating lease liabilities	Operating lease liabilities	218		214		Operating lease liabilities	211		205
Other	Other	440		407		Other	545		459
Total current liabilities	Total current liabilities	5,764		4,239		Total current liabilities	4,903		5,046

Deferred credits and other liabilities	Deferred credits and other liabilities					Deferred credits and other liabilities
Deferred income taxes	Deferred income taxes	4,913		4,746		Deferred income taxes	4,762		4,894

Deferred investment tax credits						Deferred investment tax credits	50		53
Regulatory liabilities	Regulatory liabilities	5,389		5,302		Regulatory liabilities	5,567		5,405
Asset retirement obligations	Asset retirement obligations	3,094		2,884		Asset retirement obligations	3,296		3,151
Derivative instruments	Derivative instruments	99		131		Derivative instruments	114		105
Customer advances	Customer advances	199		197		Customer advances	187		196
Pension and employee benefit obligations	Pension and employee benefit obligations	515		666		Pension and employee benefit obligations	255		306
Operating lease liabilities	Operating lease liabilities	1,187		1,344		Operating lease liabilities	997		1,146
Other	Other	207		228		Other	151		158
Total deferred credits and other liabilities	Total deferred credits and other liabilities	15,603		15,498		Total deferred credits and other liabilities	15,379		15,414

Commitments and contingencies	Commitments and contingencies	0		0		Commitments and contingencies
Capitalization	Capitalization					Capitalization
Long-term debt	Long-term debt	20,979		19,645		Long-term debt	23,309		21,779
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 538,458,952 and 537,438,394 shares outstanding at Sept. 30, 2021 and Dec. 31, 2020, respectively		1,346		1,344
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						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	Additional paid in capital	7,443		7,404		Additional paid in capital	7,979		7,803
Retained earnings	Retained earnings	6,508		5,968		Retained earnings	7,128		6,572
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(126)		(141)		Accumulated other comprehensive loss	(91)		(123)
Total common stockholders’ equity	Total common stockholders’ equity	15,171		14,575		Total common stockholders’ equity	16,384		15,612
Total liabilities and equity	Total liabilities and equity	$	57,517	$	53,957	Total liabilities and equity	$	59,975	$	57,851

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 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, 2021 and 2020
Balance at June 30, 2020		525,204,978	$	1,313	$	6,679	$	5,538	$	(145)		$	13,385
Net income							603					603
Other comprehensive income									2			2
Dividends declared on common stock ($0.43 per share)							(226)					(226)
Issuances of common stock		302,321	1		9							10
Repurchase of common stock		(54,475)	—		(4)							(4)
Share-based compensation					10		(3)					7
Balance at Sept. 30, 2020		525,452,824	$	1,314	$	6,694	$	5,912	$	(143)		$	13,777

Three Months Ended Sept. 30, 2022 and 2021														Three Months Ended Sept. 30, 2022 and 2021
Balance at June 30, 2021	Balance at June 30, 2021	538,305,927	$	1,346	$	7,435	$	6,146	$	(135)		$	14,792	Balance at June 30, 2021	538,305,927		$	1,346	$	7,435		$	6,146	$	(135)		$	14,792
Net income	Net income						609					609		Net income								609					609
Other comprehensive income	Other comprehensive income								9			9		Other comprehensive income										9			9
Dividends declared on common stock ($0.4575 per share)	Dividends declared on common stock ($0.4575 per share)						(247)					(247)		Dividends declared on common stock ($0.4575 per share)								(247)					(247)
Issuances of common stock	Issuances of common stock	153,025	—		10							10		Issuances of common stock	153,025		—		10								10

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

Balance at June 30, 2022														Balance at June 30, 2022	546,807,793		$	1,367	$	7,960		$	6,747	$	(103)		$	15,971
Net income														Net income								649					649
Other comprehensive income														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)
Issuances of common stock														Issuances of common stock	198,283		1		13								14

Share-based compensation														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
		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, 2021 and 2020
Balance at Dec. 31, 2019		524,539,000	$	1,311	$	6,656	$	5,413	$	(141)		$	13,239
															Shares		Par Value				Additional Paid In Capital					Retained Earnings			Accumulated Other Comprehensive Loss	Total Common Stockholders' Equity
Nine Months Ended Sept. 30, 2022 and 2021														Nine Months Ended Sept. 30, 2022 and 2021
Balance at Dec. 31, 2020														Balance at Dec. 31, 2020	537,438,394		$	1,344	$	7,404		$	5,968	$	(141)		$	14,575
Net income	Net income						1,185					1,185		Net income								1,282					1,282
Other comprehensive loss	Other comprehensive loss								(2)			(2)		Other comprehensive loss										15			15
Dividends declared on common stock ($1.29 per share)							(679)					(679)
Issuances of common stock		968,299	3		30							33
Repurchase of common stock		(54,475)	—		(4)							(4)
Share-based compensation					12		(5)					7
Adoption of ASC Topic 326							(2)					(2)
Balance at Sept. 30, 2020		525,452,824	$	1,314	$	6,694	$	5,912	$	(143)		$	13,777

Balance at Dec. 31, 2020		537,438,394	$	1,344	$	7,404	$	5,968	$	(141)		$	14,575
Net income							1,282					1,282
Other comprehensive income									15			15
Dividends declared on common stock ($1.373 per share)	Dividends declared on common stock ($1.373 per share)						(739)					(739)		Dividends declared on common stock ($1.373 per share)								(739)					(739)
Issuances of common stock	Issuances of common stock	1,020,558	2		38							40		Issuances of common stock	1,020,558		2		38								40

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

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

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								1,357					1,357
Other comprehensive income														Other comprehensive income										32			32
Dividends declared on common stock ($1.463 per share)														Dividends declared on common stock ($1.463 per share)								(798)					(798)
Issuances of common stock														Issuances of common stock	2,980,807		8		177								185

Share-based compensation														Share-based compensation					(1)			(3)					(4)
Balance at Sept. 30, 2022														Balance at Sept. 30, 2022	547,006,076		$	1,368	$	7,979		$	7,128	$	(91)		$	16,384

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

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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 ~~Inc. and its subsidiaries~~ as of Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020;~~2021; 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, ~~2021~~2022 and ~~2020;~~2021; and Xcel Energy’s cash flows for the nine months ended Sept. 30, ~~2021~~2022 and ~~2020.~~2021.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, ~~2021,~~2022, 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, ~~2020~~2021 balance sheet information has been derived from the audited ~~2020~~2021 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2020.~~2021.

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, ~~2020,~~2021, filed with the SEC on Feb. ~~17, 2021.~~23, 2022.

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, ~~2020~~2021 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

~~Subsequent Event~~

On Oct. 25, 2021, PSCo filed a comprehensive settlement with the CPUC Staff and the COEO, which proposes to address four outstanding regulatory items, including recovery of fuel costs related to Winter Storm Uri, disputed revenue 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. The UCA has not signed the settlement. A hearing and a CPUC decision on the settlement is expected in the first quarter of 2022.

~~Key terms of the proposed settlement:~~

•PSCo would fully recover Winter Storm Uri deferred net natural gas, fuel and purchased energy costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with 0 carrying charges through a rider mechanism. Recovery would commence Jan. 1, 2022 for electric costs and April 1, 2022 for natural gas costs.

•~~PSCo will refund electric customers $41 million (previously deferred) related to the 2020 electric decoupling pilot program.~~

•~~PSCo agreed to forego recovery of $14 million for replacement power costs due to an extended outage at Comanche Unit 3 during 2020.~~

•PSCo also agreed to not seek recovery of COVID-19 related bad debt expense, previously deferred as a regulatory asset, and recorded an additional $11 million of incremental bad debt expense for the period ended Sept. 30, 2021.


2. Accounting Pronouncements

~~Credit Losses~~— ~~In 2016,~~As of Sept. 30, 2022, there was no material impact from the ~~FASB issued~~ ~~Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326),~~ which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.

Xcel Energy implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020,recent adoption of ~~ASC Topic 326 did not have a significant~~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, 2021		Dec. 31, 2020		(Millions of Dollars)	Sept. 30, 2022		Dec. 31, 2021
Accounts receivable, net	Accounts receivable, net					Accounts receivable, net
Accounts receivable	Accounts receivable	$	1,119	$	995	Accounts receivable	$	1,308	$	1,124
Less allowance for bad debts	Less allowance for bad debts	(97)		(79)		Less allowance for bad debts	(112)		(106)
Accounts receivable, net	Accounts receivable, net	$	1,022	$	916	Accounts receivable, net	$	1,196	$	1,018


(Millions of Dollars)	(Millions of Dollars)	Sept. 30, 2021		Dec. 31, 2020		(Millions of Dollars)	Sept. 30, 2022		Dec. 31, 2021
Inventories	Inventories					Inventories
Materials and supplies	Materials and supplies	$	283	$	275	Materials and supplies	$	321	$	289
Fuel	Fuel	155		176		Fuel	234		182
Natural gas	Natural gas	149		84		Natural gas	315		160
Total inventories	Total inventories	$	587	$	535	Total inventories	$	870	$	631


(Millions of Dollars)	(Millions of Dollars)	Sept. 30, 2021		Dec. 31, 2020		(Millions of Dollars)	Sept. 30, 2022		Dec. 31, 2021
Property, plant and equipment, net	Property, plant and equipment, net					Property, plant and equipment, net
Electric plant	Electric plant	$	49,293	$	47,104	Electric plant	$	48,959	$	48,680
Natural gas plant	Natural gas plant	7,443		7,135		Natural gas plant	8,199		7,758
Common and other property	Common and other property	2,519		2,503		Common and other property	2,824		2,602
Plant to be retired (a)	Plant to be retired (a)	603		677		Plant to be retired (a)	2,258		1,200
Construction work in progress	Construction work in progress	2,263		1,877		Construction work in progress	2,445		1,969
Total property, plant and equipment	Total property, plant and equipment	62,121		59,296		Total property, plant and equipment	64,685		62,209
Less accumulated depreciation	Less accumulated depreciation	(17,711)		(16,657)		Less accumulated depreciation	(17,639)		(17,060)
Nuclear fuel	Nuclear fuel	3,065		2,970		Nuclear fuel	3,105		3,081
Less accumulated amortization	Less accumulated amortization	(2,745)		(2,659)		Less accumulated amortization	(2,864)		(2,773)
Property, plant and equipment, net	Property, plant and equipment, net	$	44,730	$	42,950	Property, plant and equipment, net	$	47,287	$	45,457

(a)~~Includes regulator-approved retirements~~Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 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 ~~jointly owned Craig Unit 1 for PSCo and Sherco Units 1 and 2 for NSP-Minnesota. Also includes SPS’ expected retirement~~coal generation assets at Pawnee pending facility gas conversion. Amounts are presented net of ~~Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.~~accumulated depreciation.


4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

~~Table of Contents~~

Commercial paper and term loan borrowings outstanding for Xcel Energy:


(Amounts in Millions, Except Interest Rates)	(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2021			Year Ended Dec. 31, 2020			(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2022			Year Ended Dec. 31, 2021
Borrowing limit	Borrowing limit	$	4,300		$	3,100		Borrowing limit	$	3,550		$	3,100
Amount outstanding at period end	Amount outstanding at period end	1,747			584			Amount outstanding at period end	158			1,005
Average amount outstanding	Average amount outstanding	1,742			1,126			Average amount outstanding	187			1,399
Maximum amount outstanding	Maximum amount outstanding	1,857			2,080			Maximum amount outstanding	329			2,054
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	0.57		%	1.45		%	Weighted average interest rate, computed on a daily basis	2.51		%	0.57		%
Weighted average interest rate at period end	Weighted average interest rate at period end	0.56			0.23			Weighted average interest rate at period end	3.40			0.31

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 ~~$19~~$39 million and ~~$20~~$19 million of letters of credit outstanding under the credit facilities at Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020,~~2021, respectively. Amounts approximate their fair value and are subject to fees.

Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities at least equal to 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, ~~2021,~~2022, 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.	$	1,250	$	529	$	721	Xcel Energy Inc.	$	1,500	$	158	$	1,342
PSCo	PSCo	700		8		692		PSCo	700		26		674
NSP-Minnesota	NSP-Minnesota	500		9		491		NSP-Minnesota	700		11		689
SPS	SPS	500		20		480		SPS	500		2		498
NSP-Wisconsin	NSP-Wisconsin	150		—		150		NSP-Wisconsin	150		—		150
Total	Total	$	3,100	$	566	$	2,534	Total	$	3,550	$	197	$	3,353

(a)Expires in ~~June 2024.~~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 ~~facilities capacity.~~facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020.~~

~~Term Loan Agreements~~ — In February 2021, Xcel Energy Inc. entered into a $1.2 billion 364-Day Term Loan Agreement that matures Feb. 17, 2022. Xcel Energy has an option to extend through Feb. 16, 2023. The term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65%.

~~As of Sept. 30, 2021, Xcel Energy Inc.’s term loan borrowings were as follows:~~

(Millions of Dollars) Limit Amount Used Available
Xcel Energy Inc. $ 1,200 $ 1,200 $ —
2021.

Bilateral Credit Agreement

In April ~~2021,~~2022, 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, ~~2021, NSP-Minnesota’s~~2022, NSP-Minnesota had $50 million of outstanding letters of credit under the $75 million bilateral credit ~~agreement were as follows:~~

(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75 $ 41 $ 34
agreement.

Long-Term Borrowings and Other Financing Instruments

During the nine months ended ~~Sept.~~September 30, ~~2021,~~2022, Xcel Energy Inc. and its utility subsidiaries issued the following:

•~~PSCo~~Xcel Energy issued ~~$750~~$700 million of ~~1.875%~~4.60% unsecured senior notes due June 1, 2032.

•NSP-Minnesota issued $500 million of 4.50% first mortgage bonds due June ~~15, 2031.~~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.

•SPS issued ~~$250~~$200 million of ~~3.15%~~5.15% first mortgage bonds due ~~May 1, 2050.~~

•~~NSP-Minnesota issued $425 million of 2.25% first mortgage bonds due April 1, 2031 and $425 million of 3.20% first mortgage bonds due April~~June 1, 2052.

•NSP-Wisconsin issued $100 million of ~~2.82%~~4.86% first mortgage bonds dudue September 15, 2052.

ATM Equity Offering — ~~e May 1, 2051.~~In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares were issued (approximately $350 million). In the second quarter of 2022, 2.13 million shares of common stock were issued (approximately $150 million). As of Sept. 30, 2022, approximately $300 million remained available for sale under the ATM program.

Other Equity — Xcel Energy Inc. issued ~~$38~~$34 million and ~~$30~~$38 million of equity through the DRIP during the nine months ended Sept. 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The program allows 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, 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
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	999	$	133	$	12	$	1,144
C&I	1,515		76		7		1,598
Other	35		—		1		36
Total retail	2,549		209		20		2,778
Wholesale	288		—		—		288
Transmission	167		—		—		167
Other	17		45		—		62
Total revenue from contracts with customers	3,021		254		20		3,295
Alternative revenue and other	155		14		3		172
Total revenues	$	3,176	$	268	$	23	$	3,467

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Three Months Ended Sept. 30, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 962 $ 124 $ 11 $ 1,097
C&I 1,340 56 5 1,401
Other 34 — 2 36
Total retail 2,336 180 18 2,534
Wholesale 227 — — 227
Transmission 157 — — 157
Other 17 28 — 45
Total revenue from contracts with customers 2,737 208 18 2,963
Alternative revenue and other 204 11 4 219
Total revenues $ 2,941 $ 219 $ 22 $ 3,182


	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

Nine Months Ended Sept. 30, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 2,356 $ 647 $ 32 $ 3,035
C&I 3,481 308 20 3,809
Other 94 — 4 98
Total retail 5,931 955 56 6,942
Wholesale 553 — — 553
Transmission 442 — — 442
Other 55 86 — 141
Total revenue from contracts with customers 6,981 1,041 56 8,078
Alternative revenue and other 449 41 11 501
Total revenues $ 7,430 $ 1,082 $ 67 $ 8,579


6. Income Taxes

~~Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on~~ ~~Form 10-K~~ ~~for the year ended Dec. 31, 2020 represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated by reference.~~

~~Difference~~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
		2021		2020		2021		2020			2022		2021		2022		2021
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)	5.0		5.0		5.0		5.1		State tax (net of federal tax effect)	4.9		5.0		4.9		5.0
Decreases:	Decreases:									Decreases:
Wind PTCs(a)	Wind PTCs(a)	(12.1)		(8.0)		(20.0)		(13.2)		Wind PTCs(a)	(12.3)		(12.1)		(25.2)		(20.0)
Plant regulatory differences ~~(a)~~(b)	Plant regulatory differences ~~(a)~~(b)	(5.8)		(7.2)		(6.0)		(7.4)		Plant regulatory differences ~~(a)~~(b)	(5.8)		(5.8)		(5.5)		(6.0)
NOL carryback		—		(1.9)		—		(1.0)
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 (net)	Other (net)	(1.5)		(2.2)		(1.3)		(2.5)		Other (net)	(0.3)		(0.3)		(0.1)		(0.2)
Effective income tax rate	Effective income tax rate	6.6	%	6.7	%	(1.3)	%	2.0	%	Effective income tax rate	6.3	%	6.6	%	(6.3)	%	(1.3)	%

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

(b)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 ~~credits~~taxes are offset by corresponding revenue reductions.

~~Federal Audits~~—~~Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:~~


~~Tax Years~~						~~Expiration~~
~~2014~~ — ~~2016~~						~~December 2022~~
~~2018~~						~~September 2022~~

Additionally, the statute of limitations related to certain federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to a federal tax loss carryback claim filed in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

~~State Audits~~ —~~Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.~~

~~As of Sept. 30, 2021, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:~~


~~State~~						~~Year~~
~~Colorado~~						~~2014~~
~~Minnesota~~						~~2013~~
~~Texas~~						~~2012~~
~~Wisconsin~~						~~2016~~

•~~In February 2021, Minnesota concluded its review and commenced an audit of tax years 2015 - 2018. No material adjustments have been proposed.~~

•~~In March 2021, Wisconsin began an audit of tax years 2016 - 2019. NaN material adjustments have been proposed.~~

•~~In April 2021, Texas began an audit of tax years 2016 - 2019. No material adjustments have been proposed.~~

•~~NaN other state income tax audits were in progress as of Sept. 30, 2021.~~

~~Table of Contents~~

~~Unrecognized Benefits~~ — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

~~Unrecognized tax benefits — permanent vs. temporary:~~

(Millions of Dollars) Sept. 30, 2021 Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions $ 46 $ 41
Unrecognized tax benefit — Temporary tax positions 11 11
Total unrecognized tax benefit $ 57 $ 52

~~Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:~~

(Millions of Dollars) Sept. 30, 2021 Dec. 31, 2020
NOL and tax credit carryforwards $ (35) $ (31)

As Internal Revenue Service audits resume and the state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $27 million in the next 12 months.

~~Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.~~

~~Interest payable related to unrecognized tax benefits:~~

(Millions of Dollars) Sept. 30, 2021 Dec. 31, 2020
Payable for interest related to unrecognized tax benefits at beginning of period $ (3) $ —
Interest expense related to unrecognized tax benefits — (3)
Payable for interest related to unrecognized tax benefits at end of period $ (3) $ (3)

~~NaN penalties were accrued related to unrecognized tax benefits as of Sept. 30, 2021 or Dec. 31, 2020.~~


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)	2021	2020	2021	2020	(Shares in Millions)	2022	2021	2022	2021
Basic	Basic	539	526	539	526	Basic	548	539	546	539
Diluted (a)	Diluted (a)	539	528	539	527	Diluted (a)	548	539	546	539

(a)Diluted common shares outstanding included common stock equivalents of 0.3 ~~million and 1.6~~ million for the three months ended ~~Sept.~~September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Diluted common shares outstanding included common stock equivalents of 0.3 ~~million~~ ~~and 1.0~~ million for the nine months ended ~~Sept.~~September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

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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.

•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 prices.

•Level 2 — Pricing inputs are other than quoted 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 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 require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled ~~funds’~~fund investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

~~Table of Contents~~

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

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

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements 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 aan 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 ~~value~~values of ~~an FTR is~~these instruments are derived from, and designed to offset, the ~~cost~~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 ~~an FTR.~~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.

If ~~forecasted~~ costs of electric transmission congestion increase or decrease for a given ~~FTR~~ path, the value of that particular ~~FTR~~ instrument will likewise increase or decrease. ~~Given~~Net congestion costs, including the ~~limited observability~~impact of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.

~~Non-trading monthly~~ FTR settlements, are ~~expected to be recovered~~shared through fuel and purchased energy cost recovery ~~mechanisms as applicable in each jurisdiction and therefore changes in~~mechanisms. As such, the fair value of the ~~yet to be settled portions of most FTRs are~~ unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements.

Non-Derivative Fair Value Measurements

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 ~~escrow and~~ investment targets by asset class for ~~both~~ the ~~escrow and~~ qualified trust.

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

Unrealized gains for the nuclear decommissioning fund were ~~$1.2~~$900 million and $1.3 billion as of Sept. 30, 2022 and ~~$981~~Dec. 31, 2021, respectively, and unrealized losses were $133 million and $7 million as of Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020, respectively, and unrealized losses were $5 million as of Sept. 30,~~ 2021, ~~and Dec. 31, 2020.~~respectively.

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


		Sept. 30, 2021													Sept. 30, 2022
				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	$	38	$	38	$	—	$	—	$	—	$	38	Cash equivalents	$	37	$	37	$	—	$	—	$	—	$	37
Commingled funds	Commingled funds	821		—		—		—		1,208		1,208		Commingled funds	832		—		—		—		1,167		1,167
Debt securities	Debt securities	620		—		643		15		—		658		Debt securities	696		—		611		9		—		620
Equity securities	Equity securities	407		1,178		2		—		—		1,180		Equity securities	409		918		1		—		—		919
Total	Total	$	1,886	$	1,216	$	645	$	15	$	1,208	$	3,084	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 ~~$204~~$214 million of equity method investments and ~~$158~~$126 million of rabbi trust assets and miscellaneous investments.

Dec. 31, 2020
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 40 $ 40 $ — $ — $ — $ 40
Commingled funds 787 — — — 1,041 1,041
Debt securities 528 — 572 13 — 585
Equity securities 446 1,109 2 — — 1,111
Total $ 1,801 $ 1,149 $ 574 $ 13 $ 1,041 $ 2,777

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	Dec. 31, 2021
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	64	$	64	$	—	$	—	$	—	$	64
Commingled funds	856		—		—		—		1,294		1,294
Debt securities	631		—		666		9		—		675
Equity securities	411		1,222		1		—		—		1,223
Total	$	1,962	$	1,286	$	667	$	9	$	1,294	$	3,256

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes ~~$165~~$208 million of equity method investments and ~~$154~~$164 million of rabbi trust assets and other miscellaneous investments.

For the three and nine months ended Sept. 30, ~~2021~~2022 and ~~2020,~~2021, 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, ~~2021:~~2022:


		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	$	2	$	153	$	204	$	299	$	658	Debt securities	$	5	$	190	$	227	$	198	$	620

Rabbi Trusts

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

Cost and fair value of assets held in rabbi trusts:

Sept. 30, 2021
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 17 $ 17 $ — $ — $ 17
Mutual funds 71 84 — — 84
Total $ 88 $ 101 $ — $ — $ 101


	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

~~Table of Contents~~


		Dec. 31, 2020											Dec. 31, 2021
				Fair Value											Fair Value
(Millions of Dollars)	(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total		(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)	Rabbi Trusts (a)											Rabbi Trusts (a)
Cash equivalents	Cash equivalents	$	32	$	32	$	—	$	—	$	32	Cash equivalents	$	20	$	20	$	—	$	—	$	20
Mutual funds	Mutual funds	60		70		—		—		70		Mutual funds	75		89		—		—		89
Total	Total	$	92	$	102	$	—	$	—	$	102	Total	$	95	$	109	$	—	$	—	$	109

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets.

Derivative Instruments 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, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.

As of Sept. 30, ~~2021,~~2022, accumulated other comprehensive loss related to interest rate derivatives included $6$2 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, Xcel Energy had no unsettled interest rate derivatives.

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. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. 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.

Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. The classification of gains or losses for these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms. As of Sept. 30, ~~2021,~~2022, 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, 2021

Dec. 31, 2020

(Amounts in Millions) (a)(b)

Sept. 30, 2022

Dec. 31, 2021

Megawatt hours of electricity

101

Megawatt hours of electricity

Million British thermal units of natural gas

184

175

Million British thermal units of natural gas

151

156

(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 in 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.

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As of Sept. 30, ~~2021, 6~~2022, five of Xcel Energy’s 10ten most significant counterparties for these activities, comprising ~~$121~~$86 million, or ~~40%~~30%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. ~~NaN~~Three of the 10ten most significant counterparties, comprising ~~$29~~$61 million, or ~~10%~~22%, 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. ~~NaN~~Two of these significant counterparties, comprising ~~$44~~$68 million, or ~~14%~~24%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. ~~NaN~~Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

~~Table of Contents~~

Impact of Derivative Activity —


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Three Months Ended Sept. 30, 2022



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, 2021
Derivatives designated as cash flow hedges:
Interest rate	$	5	$	—
Total	$	5	$	—
Other derivative instruments:
Electric commodity	$	—	$	18
Natural gas commodity	—		57
Total	$	—	$	75


~~Three Months Ended Sept. 30, 2020~~



~~Other derivative instruments:~~
~~Electric commodity~~	$	—	$	~~(3)~~
~~Natural gas commodity~~	—		2
~~Total~~	$	—	$	~~(1)~~

~~Nine Months Ended Sept. 30, 2020~~
~~Derivatives designated as cash flow hedges:~~
~~Interest rate~~	$	~~(13)~~	$	—
~~Total~~	$	~~(13)~~	$	—
~~Other derivative instruments:~~
~~Electric commodity~~	$	—	$	~~(3)~~
~~Natural gas commodity~~	—		~~(1)~~
~~Total~~	$	—	$	~~(4)~~


		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, 2022											Three Months Ended Sept. 30, 2022
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:
Commodity trading											Commodity trading			$	—		$	—		$	13	(b)
Electric commodity											Electric commodity			—			6		(c)	—

Total											Total			$	—		$	6		$	13

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

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

Total	Total	$	—		$	3		$	1		Total			$	—		$	3		$	1

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

Three Months Ended Sept. 30, 2020
Derivatives designated as cash flow hedges:
Interest rate		$	1	(a)	$	—		$	—
Total		$	1		$	—		$	—
Other derivative instruments:
Commodity trading		$	—		$	—		$	2	(b)
Electric commodity		—			(3)		(c)	—
Total		$	—		$	(3)		$	2

Nine Months Ended Sept. 30, 2020
Derivatives designated as cash flow hedges:
Interest rate		$	5	(a)	$	—		$	—
Total		$	5		$	—		$	—
Other derivative instruments:
Commodity trading		$	—		$	—		$	(1)	(b)
Electric commodity		—			(6)		(c)	—
Natural gas commodity		—			5		(d)	(6)		(d)
Total		$	—		$	(1)		$	(7)

(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.

(d)Amounts for both the three and nine months ended Sept. 30, 2021 and 2020 included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Remaining settlement losses for both the three and nine months ended Sept. 30, 2021 and 2020 relate to natural gas operations and were recordedRecorded to cost of natural gas sold and transported. These ~~gains and~~ losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, ~~or liability,~~ as appropriate.

(e)Relates primarily to option premium amortization.

Xcel Energy had no derivative instruments designated as fair value hedges during the ~~three and~~ nine months ended Sept. 30, ~~2021~~2022 and ~~2020.~~2021.

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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, ~~2021~~2022 and Dec. 31, ~~2020,~~2021, there were $2$5 million and $4$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, ~~2021~~2022 and Dec. 31, ~~2020,~~2021, there were approximately ~~$62~~$90 million and ~~$60~~$64 million, respectively, of derivative liabilities with such underlying contract provisions.

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, ~~2021~~2022 and Dec. 31, ~~2020~~2021.

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


		Sept. 30, 2021													Dec. 31, 2020																	Sept. 30, 2022																	Dec. 31, 2021
		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
Derivatives designated as cash flow hedges:
Interest rate		$	—	$	4	$	—	$	4	$	—		$	4	$	—	$	—	$	—	$	—			$	—		$	—

Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	50	$	240	$	23	$	313	$	(253)		$	60	$	2	$	67	$	1	$	70			$	(52)		$	18	Commodity trading		$	53			$	184	$	47	$	284			$	(211)	$	73		$	22		$	137	$	21	$	180		$	(134)	$	46
Electric commodity(b)	Electric commodity(b)	—		—		83		83		(1)			82		—		—		20		20				(1)			19		Electric commodity(b)		—				—		358		358				(4)		354			—			—		57		57			(1)		56
Natural gas commodity	Natural gas commodity	—		79		—		79		—			79		—		9		—		9				—			9		Natural gas commodity		—				26		—		26				—		26			—			18		—		18			—		18
Total current derivative assets	Total current derivative assets	$	50	$	323	$	106	$	479	$	(254)		225		$	2	$	76	$	21	$	99			$	(53)		46		Total current derivative assets		$	53			$	210	$	405	$	668			$	(215)	453			$	22		$	155	$	78	$	255		$	(135)	120
PPAs (b)													3															3
PPAs (c)																								PPAs (c)																		3																3
Current derivative instruments	Current derivative instruments												$	228														$	49	Current derivative instruments																$	456														$	123
Noncurrent derivative assets	Noncurrent derivative assets																													Noncurrent derivative assets
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	23	$	72	$	99	$	194	$	(129)		$	65	$	8	$	66	$	8	$	82			$	(62)		$	20	Commodity trading		$	50			$	64	$	92	$	206			$	(120)	$	86		$	16		$	63	$	89	$	168		$	(107)	$	61

Total noncurrent derivative assets	Total noncurrent derivative assets	$	23	$	72	$	99	$	194	$	(129)		65		$	8	$	66	$	8	$	82			$	(62)		20		Total noncurrent derivative assets		$	50			$	64	$	92	$	206			$	(120)	86			$	16		$	63	$	89	$	168		$	(107)	61
PPAs (b)													7															10
PPAs (c)																								PPAs (c)																		4																6
Noncurrent derivative instruments	Noncurrent derivative instruments												$	72														$	30	Noncurrent derivative instruments																$	90														$	67


		Sept. 30, 2021													Dec. 31, 2020																	Sept. 30, 2022																			Dec. 31, 2021
		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
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	48	$	239	$	25	$	312	$	(253)		$	59	$	4	$	64	$	17	$	85			$	(58)		$	27	Commodity trading		$	44			$	223	$	23		$	290			$	(219)		$	71			$	19			$	148		$	20		$	187		$	(143)		$	44
Electric commodity(b)	Electric commodity(b)	—		—		1		1		(1)			—		—		—		1		1				(1)			—		Electric commodity(b)		—				—		4		4				(4)			—				—				—			1			1			(1)			—
Natural gas commodity	Natural gas commodity	—		—		—		—		—			—		—		9		—		9				—			9		Natural gas commodity		—				12		—		12				—			12				—				8			—			8			—			8
Total current derivative liabilities	Total current derivative liabilities	$	48	$	239	$	26	$	313	$	(254)		59		$	4	$	73	$	18	$	95			$	(59)		36		Total current derivative liabilities		$	44			$	235	$	27	$	306			$	(223)		83				$	19			$	156		$	21		$	196		$	(144)		52
PPAs (b)													17															17
PPAs (c)																								PPAs (c)																		17																					17
Current derivative instruments	Current derivative instruments												$	76														$	53	Current derivative instruments																	$	100																			$	69
Noncurrent derivative liabilities	Noncurrent derivative liabilities																													Noncurrent derivative liabilities
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	22	$	69	$	120	$	211	$	(156)		$	55	$	3	$	58	$	60	$	121			$	(47)		$	74	Commodity trading		$	59			$	86	$	68	$	213			$	(132)		$	81			$	18			$	48		$	127		$	193		$	(128)		$	65
Total noncurrent derivative liabilities	Total noncurrent derivative liabilities	$	22	$	69	$	120	$	211	$	(156)		55		$	3	$	58	$	60	$	121			$	(47)		74		Total noncurrent derivative liabilities		$	59			$	86	$	68	$	213			$	(132)		81				$	18			$	48		$	127		$	193		$	(128)		65
PPAs (b)													44															57
PPAs (c)																								PPAs (c)																		33																					40
Noncurrent derivative instruments	Noncurrent derivative instruments												$	99														$	131	Noncurrent derivative instruments																	$	114																			$	105

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting ~~agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at~~agreement. At Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020. At both Sept. 30,~~ 2021, derivatives include $2 million and ~~Dec. 31, 2020, derivative assets and liabilities include $15 million of~~no obligations to return cash ~~collateral.~~collateral, respectively. At Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020,~~2021, derivative assets and liabilities include rights to reclaim cash collateral of ~~$42~~$22 million and $6$30 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 the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is 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)	2021		2020		(Millions of Dollars)	2022		2021
Balance at July 1	Balance at July 1	$	71	$	34	Balance at July 1	$	485	$	71
Purchases		2		—
Settlements		(53)		(17)
Purchases / Issuances (a)						Purchases / Issuances (a)	4		2
Settlements (a)						Settlements (a)	(106)		(53)
Net transactions recorded during the period:	Net transactions recorded during the period:					Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)		12		(25)
Net gains recognized as regulatory assets and liabilities		27		2
Gains recognized in earnings (b)						Gains recognized in earnings (b)	16		12
Net gains recognized as regulatory assets and liabilities (a)						Net gains recognized as regulatory assets and liabilities (a)	3		27
Balance at Sept. 30	Balance at Sept. 30	$	59	$	(6)	Balance at Sept. 30	$	402	$	59

		Nine Months Ended Sept. 30					Nine Months Ended Sept. 30
(Millions of Dollars)	(Millions of Dollars)	2021		2020		(Millions of Dollars)	2022		2021
Balance at Jan. 1	Balance at Jan. 1	$	(49)	$	4	Balance at Jan. 1	$	19	$	(49)
Purchases		65		49
Settlements		(101)		(59)
Purchases / Issuances (a)						Purchases / Issuances (a)	398		65
Settlements (a)						Settlements (a)	(286)		(101)
Net transactions recorded during the period:	Net transactions recorded during the period:					Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)		59		(11)
Net gains recognized as regulatory assets and liabilities		85		11
Gains recognized in earnings (b)						Gains recognized in earnings (b)	136		59
Net gains recognized as regulatory assets and liabilities (a)						Net gains recognized as regulatory assets and liabilities (a)	135		85
Balance at Sept. 30	Balance at Sept. 30	$	59	$	(6)	Balance at Sept. 30	$	402	$	59

(a)~~Presented amounts relate~~Relates primarily to FTR instruments ~~held at~~administered by MISO and SPP (annual auctions occurring in the ~~end~~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 ~~period. The consolidated income statement also includes gains~~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.

(b)Relates to commodity trading and is subject to offsetting losses ~~on Level~~of derivative instruments categorized as levels 1 and 2 ~~instruments, and Level 3 instruments settled during~~in the ~~period.~~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 for the ~~three and~~ nine months ended Sept. 30, ~~2021~~2022 and ~~2020.~~2021.

Fair Value of Long-Term Debt

Other financial instruments for which the carrying amount did not equal fair value:


		Sept. 30, 2021				Dec. 31, 2020					Sept. 30, 2022				Dec. 31, 2021
(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	$	21,600	$	24,657	$	20,066	$	24,412	Long-term debt, including current portion	$	23,960	$	20,560	$	22,380	$	25,232

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, ~~2021~~2022 and Dec. 31, ~~2020~~2021 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
		2021		2020		2021		2020			2022		2021		2022		2021
(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	$	26	$	24	$	—	$	—	Service cost	$	24	$	26	$	—	$	—
Interest cost (a)	Interest cost (a)	26		31		4		5		Interest cost (a)	28		26		3		4
Expected return on plan assets (a)	Expected return on plan assets (a)	(52)		(52)		(4)		(5)		Expected return on plan assets (a)	(52)		(52)		(4)		(4)
Amortization of prior service credit (a)	Amortization of prior service credit (a)	—		(1)		(2)		(2)		Amortization of prior service credit (a)	—		—		(2)		(2)
Amortization of net loss (a)	Amortization of net loss (a)	27		25		1		1		Amortization of net loss (a)	19		27		1		1
Settlement charge (b)	Settlement charge (b)	39		—		—		—		Settlement charge (b)	55		39		—		—
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	66		27		(1)		(1)		Net periodic benefit cost (credit)	74		66		(2)		(1)
Effects of regulation	Effects of regulation	(31)		4		1		1		Effects of regulation	(37)		(31)		1		1
Net benefit cost (credit) recognized for financial reporting	Net benefit cost (credit) recognized for financial reporting	$	35	$	31	$	—	$	—	Net benefit cost (credit) recognized for financial reporting	$	37	$	35	$	(1)	$	—


		Nine Months Ended Sept. 30									Nine Months Ended Sept. 30
		2021		2020		2021		2020			2022		2021		2022		2021
(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	$	78	$	72	$	1	$	1	Service cost	$	73	$	78	$	1	$	1
Interest cost (a)	Interest cost (a)	78		94		11		14		Interest cost (a)	83		78		11		11
Expected return on plan assets (a)	Expected return on plan assets (a)	(155)		(156)		(13)		(15)		Expected return on plan assets (a)	(156)		(155)		(13)		(13)
Amortization of prior service credit (a)	Amortization of prior service credit (a)	(1)		(3)		(6)		(6)		Amortization of prior service credit (a)	(1)		(1)		(5)		(6)
Amortization of net loss (a)	Amortization of net loss (a)	81		74		4		3		Amortization of net loss (a)	56		81		2		4
Settlement charge (b)	Settlement charge (b)	39		—		—		—		Settlement charge (b)	54		39		—		—
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	120		81		(3)		(3)		Net periodic benefit cost (credit)	109		120		(4)		(3)
Effects of regulation	Effects of regulation	(32)		7		2		2		Effects of regulation	(30)		(32)		2		2
Net benefit cost (credit) recognized for financial reporting	Net benefit cost (credit) recognized for financial reporting	$	88	$	88	$	(1)	$	(1)	Net benefit cost (credit) recognized for financial reporting	$	79	$	88	$	(2)	$	(1)

(a)The components of net periodic cost other than the service cost component are included in the line item “Other ~~(expense)~~ 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 ~~year,~~years, Xcel Energy recorded ~~a total~~ pension settlement ~~charge~~charges of $55 million and $39 million, respectively, the majority of which ~~was~~were not recognized in earnings due to the effects of regulation. A total of $7 million and $4 million of ~~that amount was~~those amounts were recorded in other expense in the third quarter ~~2021.~~of 2022 and 2021, respectively.

In January ~~2021,~~2022, contributions of ~~$125~~$50 million were made across 4four of Xcel Energy’s pension ~~plans~~.plans. Xcel Energy does not expect additional pension contributions during ~~2021.~~2022.

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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.

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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.

~~NaN~~One case remains active which includes ~~an MDL~~a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.).

~~Breckenridge/Colorado~~ The Court issued a ruling on June 30, 2022 granting plaintiffs’ class certification. Defendants will work together to prepare and file a petition appealing the class ~~— In February 2019, the MDL panel remanded Breckenridge back~~certification ruling to the ~~U.S. District Court in Colorado. Settlement of approximately $3 million was reached in February 2021. In July 2021, the settlement was approved.~~

~~Arandell Corp.~~ ~~— The trial has been vacated and will be rescheduled after the court rules on the pending motions for reconsideration and for class certification.~~Seventh Circuit. Xcel Energy has concluded that a loss is remote for the remaining lawsuit.

Comanche Unit 3 Litigation — In September 2021, CORE filed a lawsuit in Denver County District Court. CORE alleges 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 2022 outage. It claims additional undisclosed damages arising from this event. PSCo continues to believe CORE's claims are without merit.

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 ~~FCA.~~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 ~~FCA.~~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. A final decision by the MPUC is ~~pending.~~expected in mid-2023. A loss related to this matter is deemed remote.

~~Westmoreland Arbitration~~ —In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPA and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards.

NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for Nov. 15, 2021. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined.

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%.

In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit subsequently vacated and remanded Opinion No. 551.

~~In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period.~~ The FERC ~~also dismissed the second complaint. In December 2019, MISO TOs filed a request~~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 ~~rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second~~applicable complaint ~~without refunds.~~

In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint.

~~In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change~~periods based on the ROE ~~effective Sept. 28, 2016, and for~~in the ~~first MISO complaint period and upheld its decision to deny refunds for the second complaint period.~~ ~~NSP-Minnesota~~ has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in ROE for the first complaint period, second complaint period, and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.most recent applicable opinions.

The MISO TOs and various other parties have filed petitions for review of ~~Opinion Nos. 569, 569-A and 569-B~~the FERC’s most recent applicable opinions at the D.C. Circuit. ~~A hearing is expected in~~In August 2022, the ~~fourth quarter of 2021 with a decision anticipated in~~D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders, and remanded the ~~first half of 2022.~~

issue back to FERC ~~NOPR on ROE Incentive Adders~~ ~~— In April 2021, the FERC issued a NOPR proposing to limit collection of ROE incentive adders~~ for RTO membership to the first three years after an entity begins participation in an RTO. If adopted as a final rule, NSP-Minnesota, NSP-Wisconsin and SPS would prospectively discontinue charging their current 50 basis point ROE incentive adders. Amounts related to a discontinuance of the adder would ultimately be offset by an increase in retail rates, subject to future rate cases.further proceedings, which remain pending.

~~Table of Contents~~

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.

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 issued a tolling order granting a rehearing for further consideration in May 2018. 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 at the D.C. Circuit. In February 2022, FERC ~~has asked that this appeal be stayed until early 2022, in order to provide FERC with time to issue~~issued an order onrejecting SPS’ ~~April 2018 rehearing request. The D.C. Circuit~~request for hearing. SPS has appealed that order. That appeal ~~may resume after that FERC order is issued.~~has been combined with SPS’ prior appeal.

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 ~~ERCOT~~Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million, ~~(lump sum or annual installments),~~ 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 ~~settlement~~ agreement is subject to approval by the PUCT and FERC.

~~Comanche Unit 3 Litigation~~ — ~~In February 2021,~~ Approval steps are in process, but approval timing from the joint owners of Comanche Unit 3 (CORE Electric Cooperative, formerly known as Intermountain Rural Electrical Association, and Holy Cross Electric) served PSCo with a notice of claim related to Comanche Unit 3's operation and availability.

~~Discussions with Holy Cross Electric are proceeding pursuant to a contractual dispute resolution process and the amount of any alleged damages depends on multiple factors and~~PUCT is ~~currently unknown.~~

In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado state court seeking an unspecified amount of damages. CORE Electric Cooperative alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo is continuing to assess legal options in response to the Complaint including assertions of affirmative defenses.

~~GCA NOPR~~ — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The proposed rule would establish an annual forecast of GCA costs for each utility and allow each utility to recover only 90%-95% of any costs in excess of the forecasted amount. The proposed rule would allow utilities to earn an incentive equal to an undefined portion of any savings relative to forecasted costs. Comments were filed and requested that the CPUC delay the rule making process until after the 2021-2022 heating season; in part because utilities have already proceeded with purchasing gas for the upcoming heating season in accordance with prior CPUC decisions. In August 2021, the CPUC announced they would postpone a decision to a future date.uncertain.

Environmental

MGP, Landfill and Disposal Sites

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

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

Environmental Requirements — Water and Waste

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

As of Sept. 30, 2022, Xcel Energy ~~has 8~~had eight regulated ash units in operation.

Xcel Energy is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, increases above background concentrations were detected at 4 locations. Based on further assessments, PSCo is ~~evaluating options~~currently exploring an agreement with a third party that would excavate and process ash for beneficial use (at two sites) at a cost of approximately $43 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 ~~at 2 locations, 1 of which indicates potential~~related to offsite ~~impacts~~groundwater are ongoing (at two sites). While the results are uncertain, additional costs are estimated to ~~groundwater. The total cost is uncertain, but could~~ be up to $35 million. ~~PSCo is continuing~~An estimated liability has been recorded for the portion of these actions that are estimable, and are expected to ~~assess~~be fully recoverable through regulatory mechanisms.

Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the ~~financial~~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 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory ~~impacts.~~mechanisms.

Environmental Requirements — Air

Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes sulfur dioxide emission limitations which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.

In ~~August 2020,~~2017, the Fifth Circuit remanded the rule to the EPA ~~published its final rule to implement closure by April 2021~~ for ~~all CCR impoundments affected by~~reconsideration (leaving the ~~August 2018 D.C. Circuit ruling. This final rule required Xcel Energy to expedite closure plans for 2 impoundments.~~

stay in effect). In ~~October 2020, NSP-Minnesota completed construction and placed in service~~ a ~~new impoundment to replace~~future rulemaking, the clay lined impoundment at a cost of $9 million. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.

PSCo also built an alternative collection and treatment system to remove the Comanche Station bottom ash pond from service. The total cost of the alternate treatment system is approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline, but was not able to remove the pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the EPA. PSCo will also now proceed with closure of the pond, with an estimated cost of $3 million. Closure costs for existing impoundmentsEPA may address whether further sulfur dioxide emission reductions are ~~included in the calculation of the asset retirement obligation.~~necessary.

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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)	2021		2020		(Millions of Dollars)	2022		2021
Operating leases	Operating leases					Operating leases
PPA capacity payments	PPA capacity payments	$	56	$	56	PPA capacity payments	$	59	$	56
Other operating leases (a)	Other operating leases (a)	2		5		Other operating leases (a)	8		2
Total operating lease expense (b)	Total operating lease expense (b)	$	58	$	61	Total operating lease expense (b)	$	67	$	58
Finance leases	Finance leases					Finance leases
Amortization of ROU assets	Amortization of ROU assets	$	2	$	2	Amortization of ROU assets	$	1	$	2
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	$	6	$	6	Total finance lease expense	$	5	$	6

(a)Includes short-term lease expense of $1 million for 2022 and ~~$2 million for 2021 and 2020, respectively.~~2021.

(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
(Millions of Dollars) 2021 2020
Operating leases
PPA capacity payments $ 170 $ 145
Other operating leases (a)
19 22
Total operating lease expense (b)
$ 189 $ 167
Finance leases
Amortization of ROU assets $ 6 $ 5
Interest expense on lease liability 12 13
Total finance lease expense $ 18 $ 18


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

(a)Includes short-term lease expense ~~of $4~~of $4 million for ~~2021~~2022 and ~~2020, respectively.~~2021.

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Commitments under operating and finance leases as of Sept. 30, ~~2021:~~2022:


(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	$	1,470	$	191	$	1,661	$	246	Total minimum obligation	$	1,246	$	166	$	1,412	$	239
Interest component of obligation	Interest component of obligation	(221)		(35)		(256)		(173)		Interest component of obligation	(174)		(30)		(204)		(169)
Present value of minimum obligation	Present value of minimum obligation	$	1,249	156		1,405		73		Present value of minimum obligation	$	1,072	136		1,208		70
Less current portion	Less current portion					(218)		(3)		Less current portion					(211)		(4)
Noncurrent operating and finance lease liabilities	Noncurrent operating and finance lease liabilities					$	1,187	$	70	Noncurrent operating and finance lease liabilities					$	997	$	66

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

~~VIEs~~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~~mately~~ ma~~4,062~~tely 3,961 MW and 4,062 MW of capacity under long-term PPAs at ~~both~~ Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020~~2021, respectively, with entities that have been determined to be ~~VIEs.~~variable interest entities. 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 PPAs have expiration dates through 2041.

Other

Guarantees and Bond Indemnifications — Xcel Energy ~~Inc. and its subsidiaries provide~~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 ~~Inc. and its subsidiaries~~ have a stated maximum amount.

As of Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020,~~2021, Xcel Energy ~~Inc. and its subsidiaries~~ 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 ~~$60 million~~ ~~and~~ $62 million and $60 million at Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020, respectively.~~2021, respectively.

Other Indemnification Agreements — Xcel Energy ~~Inc. and its subsidiaries provide~~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 Inc.’s and its subsidiaries’~~Energy’s obligations under these agreements may be limited in duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated.

~~Table of Contents~~


11. Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, ~~2021~~2022 and ~~2020:~~2021:


		Three Months Ended Sept. 30, 2021						Three Months Ended Sept. 30, 2020							Three Months Ended Sept. 30, 2022						Three Months Ended Sept. 30, 2021
(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	$	(80)	$	(55)	$	(135)	$	(87)	$	(58)	$	(145)	Accumulated other comprehensive loss at July 1	$	(57)	$	(46)	$	(103)	$	(80)	$	(55)	$	(135)
Other comprehensive gain before reclassifications (net of taxes of $1, $—, $— and $—, respectively)		3		—		3		—		—		—
Other comprehensive gain before reclassifications														Other comprehensive gain before reclassifications	—		10		10		3		—		3
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 (net of taxes of $—, $—, $— and $—, respectively) (a)		2		—		2		1		—		1
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) (b)		—		4		4		—		1		1
Interest rate derivatives (a)														Interest rate derivatives (a)	1		—		1		2		—		2
Amortization of net actuarial loss (b)														Amortization of net actuarial loss (b)	—		1		1		—		4		4
Net current period other comprehensive income	Net current period other comprehensive income	5		4		9		1		1		2		Net current period other comprehensive income	1		11		12		5		4		9
Accumulated other comprehensive loss at Sept. 30	Accumulated other comprehensive loss at Sept. 30	$	(75)	$	(51)	$	(126)	$	(86)	$	(57)	$	(143)	Accumulated other comprehensive loss at Sept. 30	$	(56)	$	(35)	$	(91)	$	(75)	$	(51)	$	(126)


		Nine Months Ended Sept. 30, 2021						Nine Months Ended Sept. 30, 2020							Nine Months Ended Sept. 30, 2022						Nine Months Ended Sept. 30, 2021
(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	$	(85)	$	(56)	$	(141)	$	(80)	$	(61)	$	(141)	Accumulated other comprehensive loss at Jan. 1	$	(75)	$	(48)	$	(123)	$	(85)	$	(56)	$	(141)
Other comprehensive gain (loss) before reclassifications (net of taxes of $1, $—, $(3) and $—, respectively)		4		—		4		(10)		—		(10)
Other comprehensive gain before reclassifications														Other comprehensive gain before reclassifications	15		11		26		4		—		4
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 (net of taxes of $1, $—, $1 and $—, respectively) (a)		6		—		6		4		—		4
Amortization of net actuarial loss (net of taxes of $—, $2, $— and $1, respectively) (b)		—		5		5		—		4		4
Net current period other comprehensive income (loss)		10		5		15		(6)		4		(2)
Interest rate derivatives (a)														Interest rate derivatives (a)	4		—		4		6		—		6
Amortization of net actuarial loss (b)														Amortization of net actuarial loss (b)	—		2		2		—		5		5
Net current period other comprehensive income														Net current period other comprehensive income	19		13		32		10		5		15
Accumulated other comprehensive loss at Sept. 30	Accumulated other comprehensive loss at Sept. 30	$	(75)	$	(51)	$	(126)	$	(86)	$	(57)	$	(143)	Accumulated other comprehensive loss at Sept. 30	$	(56)	$	(35)	$	(91)	$	(75)	$	(51)	$	(126)

(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.

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 and the operations of MEC until July 2020.~~credits.

Xcel Energy had equity method investments of ~~$204~~$214 million and ~~$165~~$208 million as of Sept. 30, ~~2021~~2022 and Dec. 31, ~~2020,~~2021, 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
(Millions of Dollars)	2022		2021
Regulated Electric


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


	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

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~~Xcel Energy’s segment information:~~

Three Months Ended Sept. 30
(Millions of Dollars) 2021 2020
Regulated Electric
Operating revenues — external $ 3,176 $ 2,941
Intersegment revenue — 1
   Total revenues $ 3,176 $ 2,942
Net income 629 632
Regulated Natural Gas
Operating revenues — external $ 268 $ 219
Intersegment revenue 1 —
   Total revenues 269 219
Net income 10 —
All Other
Total revenues $ 23 $ 22
Net loss (30) (29)
Consolidated Total
Total revenues $ 3,468 $ 3,183
Reconciling eliminations (1) (1)
   Total operating revenues $ 3,467 $ 3,182
Net income 609 603

Nine Months Ended Sept. 30
(Millions of Dollars) 2021 2020
Regulated Electric
Operating revenues — external $ 8,643 $ 7,430
Intersegment revenue 1 1
   Total revenues $ 8,644 $ 7,431
Net income 1,202 1,148
Regulated Natural Gas
Operating revenues — external $ 1,364 $ 1,082
Intersegment revenue 2 1
   Total revenues 1,366 1,083
Net income $ 161 $ 111
All Other
Total revenues 69 67
Net loss $ (81) $ (74)
Consolidated Total
Total revenues $ 10,079 $ 8,581
Reconciling eliminations (3) (2)
   Total operating revenues $ 10,076 $ 8,579
Net income 1,282 1,185

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 ~~electric margin, natural gas margin,~~ 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.

~~Electric and Natural Gas Margins~~

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

Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales — ~~other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).~~

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.

~~Table of Contents~~

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries.

For the three and nine months ended Sept. 30, ~~2021~~2022 and ~~2020,~~2021, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

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

Summarized diluted EPS for Xcel Energy:


		Three Months Ended 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	2021		2020		2021		2020		Diluted Earnings (Loss) Per Share	2022		2021		2022		2021
PSCo	PSCo	$	0.40	$	0.42	$	0.96	$	0.87	PSCo	$	0.45	$	0.40	$	1.02	$	0.96
NSP-Minnesota	NSP-Minnesota	0.46		0.46		0.91		0.89		NSP-Minnesota	0.49		0.46		0.94		0.91
SPS	SPS	0.25		0.24		0.48		0.46		SPS	0.25		0.25		0.52		0.48
NSP-Wisconsin	NSP-Wisconsin	0.07		0.08		0.15		0.16		NSP-Wisconsin	0.07		0.07		0.19		0.15
Earnings from equity method investments — WYCO	Earnings from equity method investments — WYCO	0.01		0.01		0.03		0.04		Earnings from equity method investments — WYCO	0.01		0.01		0.03		0.03
Regulated utility (a)	Regulated utility (a)	1.19		1.21		2.54		2.42		Regulated utility (a)	1.28		1.19		2.69		2.54
Xcel Energy Inc. and Other	Xcel Energy Inc. and Other	(0.06)		(0.07)		(0.16)		(0.17)		Xcel Energy Inc. and Other	(0.09)		(0.06)		(0.21)		(0.16)
Total (a)	Total (a)	$	1.13	$	1.14	$	2.38	$	2.25	Total (a)	$	1.18	$	1.13	$	2.48	$	2.38

(a) Amounts may not add due to rounding.

Summary of Earnings

Xcel Energy — Xcel Energy’s GAAP third quarter diluted earnings were $1.18 per share in 2022 compared with $1.13 per share in ~~2021 compared with $1.14 per share in 2020 for the third quarter of 2021 and increased $0.13 per share year-to-date. Higher depreciation and lower AFUDC were~~2021. The increase was driven by regulatory rate outcomes, partially offset by higher depreciation, 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 in electric and natural gas ~~margins (driven~~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 ~~capital investment recovery and other regulatory outcomes) and lower O&M expenses.~~the related variation in revenues).

PSCo — Earnings ~~decreased $0.02~~increased $0.05 per share for the third quarter of ~~2021~~2022 and ~~increased $0.09 per share~~$0.06 year-to-date. ~~The increase in~~Higher year-to-date earnings ~~reflects higher natural gas and electric margins (regulatory~~reflect regulatory rate outcomes, ~~to primarily recover capital investments), partially offset by additional depreciation, O&M expenses and other taxes (other than income taxes).~~

~~NSP-Minnesota~~ — Earnings were flat for the third quarter of 2021 and increased $0.02 per share year-to-date. The increase in year-to-date earnings reflects higher electric margin (regulatory outcomes to primarily recover capital investments), partially offset by increased depreciation and O&M expenses.

~~SPS~~NSP-Minnesota — Earnings increased ~~$0.01~~$0.03 per share for the third quarter of ~~2021~~2022 and ~~$0.02~~year-to-date. The year-to-date increase is primarily due to regulatory rate outcomes, partially offset by increased depreciation, O&M expenses and a Winter Storm Uri cost disallowance.

SPS — Earnings were flat for the third quarter of 2022 and increased $0.04 per share year-to-date. ~~The increase in~~Higher year-to-date earnings ~~reflects higher electric margin (capital investment recovery~~largely reflect regulatory rate outcomes, strong sales growth and ~~regulatory outcomes),~~favorable weather, partially offset by ~~decreased AFUDC.~~higher depreciation, O&M expenses and interest charges.

NSP-Wisconsin — Earnings ~~decreased $0.01 per share~~were flat for the third quarter of ~~2021~~2022 and ~~$0.01~~increased $0.04 per share year-to-date. The ~~decrease in~~ year-to-date ~~earnings~~increase is ~~largely driven by higher O&M expenses~~due to regulatory rate outcomes and ~~income tax expense,~~sales growth, partially offset by higher ~~electric margin~~depreciation and ~~lower depreciation.~~O&M expenses.

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

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Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in ~~2021~~2022 EPS compared to ~~2020:~~2021:

Diluted Earnings (Loss) Per Share Three Months Ended Sept. 30 Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2020 $ 1.14 $ 2.25
Components of change - 2021 vs. 2020
Higher electric margin 0.01 0.25
Higher natural gas margins 0.03 0.15
Lower ETR (a)
0.01 0.12
Higher other (expense) income, net (0.01) 0.02
Lower interest charges 0.01 —
Lower (Higher) O&M expenses 0.02 (0.06)
Lower AFUDC (0.02) (0.09)
Higher depreciation and amortization (0.03) (0.19)
Other, net (0.03) (0.07)
GAAP and ongoing diluted EPS — 2021 $ 1.13 $ 2.38


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

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

Statement of Income Analysis

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

Estimated Impact of Temperature Changes on Regulated Earnings —Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, ~~sales true-up and~~ decoupling mechanisms in ~~Minnesota~~Colorado and ~~Colorado~~proposed sales true-up mechanisms in Minnesota predominately mitigate the positive and adverse impacts of ~~weather.~~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.

~~Table of Contents~~

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


		Three Months Ended Sept. 30						Nine Months Ended Sept. 30							Three Months Ended Sept. 30						Nine Months Ended Sept. 30
		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020			2022 vs. Normal		2021 vs. Normal		2022 vs. 2021		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021
HDD	HDD	(50.5)	%	48.4	%	(65.8)	%	0.1	%	(2.8)	%	1.5	%	HDD	(27.8)	%	(50.5)	%	36.0	%	8.3	%	0.1	%	7.5	%
CDD	CDD	18.1		20.7		(9.1)		11.7		21.2		(8.1)		CDD	23.0		18.1		13.0		24.7		11.7		17.8
THI	THI	6.2		4.6		2.4		25.5		7.0		18.7		THI	1.7		6.2		(4.2)		6.4		25.5		(14.4)

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
		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020			2022 vs. Normal		2021 vs. Normal		2022 vs. 2021		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021
Retail electric	Retail electric	$	0.067	$	0.079	$	(0.012)	$	0.122	$	0.096	$	0.026	Retail electric	$	0.074	$	0.067	$	0.007	$	0.123	$	0.122	$	0.001
Decoupling and sales true-up	Decoupling and sales true-up	(0.035)		(0.035)		—		(0.076)		(0.044)		(0.032)		Decoupling and sales true-up	(0.032)		(0.035)		0.003		(0.055)		(0.076)		0.021
Electric total	Electric total	$	0.032	$	0.044	$	(0.012)	$	0.046	$	0.052	$	(0.006)	Electric total	$	0.042	$	0.032	$	0.010	$	0.068	$	0.046	$	0.022
Firm natural gas	Firm natural gas	—		—		—		0.004		(0.005)		0.009		Firm natural gas	—		—		—		0.019		0.004		0.015
Total	Total	$	0.032	$	0.044	$	(0.012)	$	0.050	$	0.047	$	0.003	Total	$	0.042	$	0.032	$	0.010	$	0.087	$	0.050	$	0.037

Sales — Sales growth (decline) for actual and weather-normalized sales in ~~2021~~2022 compared to ~~2020:~~2021:


		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	0.4	%	0.3	%	(7.8)	%	(2.0)	%	(1.0)	%	Electric residential	(1.7)	%	(2.7)	%	7.8	%	(0.1)	%	(0.7)	%
Electric C&I	Electric C&I	2.1		3.4		4.4		1.9		3.1		Electric C&I	(2.3)		0.2		7.2		3.7		1.6
Total retail electric sales	Total retail electric sales	1.4		2.3		1.7		0.8		1.8		Total retail electric sales	(2.0)		(0.8)		7.3		2.6		0.9
Firm natural gas sales	Firm natural gas sales	(2.0)		(0.8)		N/A		(7.8)		(2.0)		Firm natural gas sales	(1.6)		—		N/A		2.3		(0.9)


		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
Weather-Normalized	Weather-Normalized											Weather-Normalized
Electric residential	Electric residential	2.2	%	(0.3)	%	(1.4)	%	0.1	%	0.5	%	Electric residential	(4.6)	%	0.5	%	3.3	%	(0.1)	%	(1.1)	%
Electric C&I	Electric C&I	1.8		3.1		5.3		2.2		3.2		Electric C&I	(3.2)		0.4		6.4		3.5		1.2
Total retail electric sales	Total retail electric sales	1.9		2.0		3.8		1.6		2.4		Total retail electric sales	(3.7)		0.4		5.9		2.5		0.5
Firm natural gas sales	Firm natural gas sales	2.2		4.2		N/A		(4.6)		2.4		Firm natural gas sales	(1.5)		(2.2)		N/A		—		(1.6)

Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential 2.1 % 3.5 % (2.1) % 1.7 % 2.0 %
Electric C&I 1.0 2.1 1.5 3.6 1.7
Total retail electric sales 1.4 2.5 0.8 3.0 1.8
Firm natural gas sales 6.9 (1.8) N/A (0.9) 3.7


	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(2.9)	%	(1.4)	%	4.9	%	1.3	%	(0.9)	%
Electric C&I	(0.3)		2.3		9.6		3.6		3.6
Total retail electric sales	(1.2)		1.1		8.6		2.9		2.2
Firm natural gas sales	(3.4)		19.9		N/A		20.2		4.9

Table of Contents

Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential 2.6 % 0.9 % 0.4 % 0.4 % 1.4 %
Electric C&I 0.9 1.4 2.0 3.2 1.5
Total retail electric sales 1.5 1.2 1.7 2.4 1.5
Firm natural gas sales 2.4 (1.1) N/A (1.0) 1.0


		Nine Months Ended Sept. 30 (2020 Leap Year Adjusted)											Nine Months Ended Sept. 30
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized	Weather-Normalized											Weather-Normalized
Electric residential	Electric residential	3.0	%	1.2	%	0.7	%	0.8	%	1.8	%	Electric residential	(3.7)	%	0.6	%	0.7	%	0.6	%	(1.0)	%
Electric C&I	Electric C&I	1.3		1.8		2.4		3.6		1.9		Electric C&I	(0.5)		2.7		9.0		3.8		3.5
Total retail electric sales	Total retail electric sales	1.9		1.6		2.0		2.7		1.9		Total retail electric sales	(1.6)		2.0		7.4		2.8		2.2
Firm natural gas sales	Firm natural gas sales	3.2		(0.3)		N/A		(0.2)		1.8		Firm natural gas sales	(2.4)		6.0		N/A		7.4		0.9

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

Weather-adjusted sales results for each of our utility subsidiaries in 2021 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated from pre-pandemic levels due to continuance of individuals working from home.

•PSCo — Residential sales ~~rose based on a 1.2% increase in customers combined with higher~~declined due to decreased use per ~~customer. The growth in C&I sales was due to~~customer, partially offset by a 1.1% increase in ~~customers and slightly higher~~customers. C&I sales decline was attributable 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 ~~sector.~~and health care sectors.

•NSP-Minnesota — Residential sales growth reflects a 1.2% increase in ~~customers. The growth~~customers, partially offset by decreased use per customer. Growth in C&I sales was primarily due to ~~a 0.9% increase in customers and slightly~~ higher use per customer, ~~primarily~~particularly in the manufacturing, ~~sector.~~real estate and leasing, and food service sectors.

•SPS — Residential sales ~~rose based on~~growth was primarily attributable to a ~~0.8%~~1.0% increase in customers, ~~despite slightly~~partially offset by a lower 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 ~~attributable to~~driven by a ~~0.8%~~0.7% increase in ~~customer additions. The growth in~~customers. C&I sales growth was ~~due to a 1.1% increase in customers,~~ primarily ~~led by increases~~associated with higher use per customer, experienced primarily in the ~~services sector.~~transportation and manufacturing sectors.

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

•Natural gas sales ~~primarily~~ reflect a ~~1.2% increase~~higher use per customer, experienced primarily in NSP-Minnesota and NSP-Wisconsin partially offset by a decrease in PSCo (lower residential ~~customers~~use per customer). In addition, residential and ~~a 0.6% increase in~~ C&I ~~customers, combined with slightly higher~~ customer ~~use.~~growth was 1.2% and 0.5%, 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 ~~on electric margin~~ due to fuel recovery mechanisms that recover fuel expenses. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue ~~margin~~ and income taxes.

Electric revenues, fuel and purchased power and margin and explanation of the changes are listed as follows:


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


(Millions of Dollars)	Three Months Ended Sept. 30, 2022 vs. 2021		Nine Months Ended Sept. 30, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)	$	165	$	361
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
Estimated impact of weather (net of decoupling/sales true-up)	7		16
PTCs flowed back to customers (offset by lower ETR)	(17)		(120)
Proprietary commodity trading, net of sharing (c)	(1)		(33)

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

(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs, see Public Utility Regulation for additional information.

(b)Sales excludes weather impact, net of decoupling in Colorado 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 revenues, cost of natural gas sold and transported and margin and explanation of the changes are listed as follows:


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


(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

Table of Contents

~~Electric revenues and margin:~~

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2021 2020 2021 2020
Electric revenues $ 3,176 $ 2,941 $ 8,643 $ 7,430
Electric fuel and purchased power (1,210) (981) (3,643) (2,611)
Electric margin $ 1,966 $ 1,960 $ 5,000 $ 4,819

~~Changes in electric margin:~~

(Millions of Dollars) Three Months Ended Sept. 30, 2021 vs. 2020 Nine Months Ended Sept. 30, 2021 vs. 2020
Non-fuel riders $ 59 $ 196
Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota) 30 106
Proprietary commodity trading, net of sharing (a)
11 49
Sales and demand (b)
10 20
Estimated impact of weather (net of decoupling/sales true-up) (8) (3)
Texas 2019 rate case surcharge (c)
(70) (70)
PTCs flowed back to customers (offset by lower ETR) (31) (111)
Other (net) 5 (6)
Total increase in electric margin $ 6 $ 181

~~(a)~~Includes $27 million of net gains previously recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri. Additional amounts are primarily related to long-term physical generation contracts, which have increased in value as a result of higher energy prices.

~~(b)Sales excludes weather impact, net of decoupling/sales true-up, and demand is net of sales true-up.~~

~~(c)Impact to electric margin is due to the Texas rate case outcome, which was recognized in the third quarter of 2020 and was largely offset by recognition of previously deferred costs.~~

~~Natural Gas Margin~~

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

~~Natural gas revenues and margin:~~

Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2021 2020 2021 2020
Natural gas revenues $ 268 $ 219 $ 1,364 $ 1,082
Cost of natural gas sold and transported (86) (54) (603) (425)
Natural gas margin $ 182 $ 165 $ 761 $ 657

~~Changes in natural gas margin:~~

(Millions of Dollars) Three Months Ended Sept. 30, 2021 vs. 2020 Nine Months Ended Sept. 30, 2021 vs. 2020
Regulatory rate outcomes (Colorado) $ 13 $ 84
Infrastructure and integrity riders 3 7
Estimated impact of weather (1) 7
Other (net) 2 6
Total increase in natural gas margin $ 17 $ 104

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses ~~decreased $11~~increased $43 million ~~or 1.9%,~~ for the third quarter and ~~increased $44~~$75 million ~~or 2.6%~~ year-to-date. ~~Significant changes are summarized as follows:~~

(Millions of Dollars) Three Months Ended Sept. 30, 2021 vs. 2020 Nine Months Ended Sept. 30, 2021 vs. 2020
Wind $ 14 $ 36
Information technology and security 3 20
Distribution 9 16
Bad debt expense - PSCo settlement (See Note 1 to the consolidated financial statements) 11 11
Natural gas systems (4) 5
Texas rate case deferral (offset in electric margin) (17) (14)
Benefits (24) (31)
Other (3) 1
Total (decrease) increase in O&M expenses $ (11) $ 44

~~The year-to-date increase was primarily~~O&M costs increased due to ~~expenses associated with new wind farms, software infrastructure and security costs, additional distribution expenses (vegetation management), bad debt expense~~recognition of previously deferred amounts related to the ~~PSCo settlement~~2021 Texas Electric Rate Case, additional investments in technology and ~~natural gas damage prevention. Increases~~customer programs, higher costs for storms and vegetation management and inflationary impacts. These increases were partially offset by ~~recognition~~a reduction in employee benefit costs and timing of previous deferrals for Texas rate case activity in 2020 (offset in electric margin) and a decrease in benefits expense (primarily related to long term incentives). Quarterly timing impacts also occurred throughout 2020 due to cost control initiatives to mitigate the adverse impact of COVID-19 on sales.certain power plant overhaul costs.

Depreciation and Amortization — Depreciation and amortization increased ~~$24~~$70 million ~~or 4.7%,~~ for the third quarter and ~~$137~~$221 million ~~or 9.5%~~ year-to-date. The increase was primarily driven by normal system expansion, recognition of previously deferred costs related to the Texas Electric Rate Case and several wind farms going into service, normal system expansion and the implementation of new depreciation rates in various states. In addition, depreciation for the third quarter of 2020 reflected the recognition of previously deferred expenses associated with the Texas rate case.service.

Other (Expense) Income— Other (expense) income decreased $4$12 million for the third quarter and ~~increased $11~~$25 million ~~year-to-date. Changes were~~year-to-date, largely related to ~~fluctuations in~~ rabbi trust performance, which is primarily offset in O&M ~~expenses.~~

~~AFUDC, Equity and Debt~~ ~~— AFUDC decreased $13 million for the third quarter of 2021 and $53 million year-to-date. The decrease was primarily driven by completion of various wind projects.~~expenses (employee benefit costs).

Interest Charges — Interest charges ~~decreased $10~~increased $33 million ~~or 4.5%,~~ for the third quarter and ~~were flat year-to-date. The quarter-to-date decrease was~~$77 million year-to-date, largely due to ~~the timing of interest deferrals associated with the Texas rate case and lower~~higher interest rates ~~partially offset by higher~~and increased long-term debt levels ~~primarily due~~ to ~~Winter Storm Uri.~~fund capital investments.

~~Earnings from Equity Method Investments~~Income Taxes — ~~— Earnings from equity method investments~~Income tax expense increased $1 million for the third quarter and ~~$18~~income tax benefit increased $63 million year-to-date. The year-to-date ~~increase was largely attributable to the performance of the EIP funds, which invest in energy technology companies.~~

~~Table of Contents~~

~~Income Taxes~~ — ~~Income tax benefit increased $41 million year-to-date. The~~ increase was primarily driven by an increase in wind PTCs due to ~~additional~~greater production at existing wind ~~facilities~~farms, several new wind farms going into ~~service.~~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. Impact of PTCs was partially offset by an increase in pretax earnings, lower plant regulatory differences, a carryback tax benefit in 2020 and lower non-plant accumulated deferred income tax amortization.


~~Other~~

~~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 the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $985 million (largely deferred as regulatory assets) in the first quarter.

~~Regulatory Overview~~ —Xcel Energy has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February cost increases for future recovery and are proposing to recover the cost increases over a period of up to 30 months to mitigate the impact to customer bills. Additionally, we are not requesting recovery of financing costs in order to further limit the impact to our customers.

~~Proceedings initiated:~~


~~Utility Subsidiary~~	~~Jurisdiction~~	~~Regulatory Status~~
~~NSP-Minnesota~~	~~Minnesota~~	NSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. The DOC recommended disallowances of $21 million related to the utilization of natural gas storage. The OAG recommended disallowances of $34 million based on: (1) utilization of natural gas storage; (2) failure to enter fixed-price contracts; (3) failure to maximize curtailments to interruptible customers; and (4) inadequate conservation efforts to reduce demand. In addition, intervenors raised questions regarding peaking plant availability. In August 2021, the MPUC allowed the utilities to start recovery of all Uri storm costs starting in September 2021 over 27 months (no financing charge). The cost recovery will be subject to refund pending the outcome of a contested case before an ALJ that will consider the DOC/OAG recommendations and issues related to the peaking plants. A decision is expected in the summer of 2022.
	~~South Dakota~~	~~Winter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the electric market.~~
	~~North Dakota~~	~~In June, the NDPSC approved recovery of $32 million in natural gas costs over 15 months (starting July 2021) with no financing charge.~~
~~NSP-Wisconsin~~	~~Wisconsin~~	~~In March, the PSCW approved NSP-Wisconsin’s proposal to recover $45 million of Uri natural gas costs over nine months through December 2021 with no financing charge.~~
	~~Michigan~~	~~In May, the Michigan Public Service Commission approved recovery of $2 million in natural gas costs over 10 months with no financing charge.~~


~~Utility Subsidiary~~	~~Jurisdiction~~	~~Regulatory Status~~
~~PSCo~~	~~Colorado~~	In May, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental gas costs and $4 million in incremental steam costs over 24 months with no financing charge. In September, intervenors filed testimony. The CPUC Staff recommended disallowances of approximately $99 million (electric) and $105 million (natural gas). Additionally, they proposed to net approximately $50 million of regulatory liabilities (decoupling related) from electric costs. The UCA recommended disallowances of approximately $131 million. The COEO recommended disallowances of approximately $46 million for not utilizing demand response programs during the event. In October, a partial settlement was reached with the CPUC Staff and the COEO. See Note 1 of the accompanying consolidated financial statements for further discussion. ~~A decision is expected in the first quarter of 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery.~~
~~SPS~~	~~Texas~~	As part of the Texas fuel surcharge filing, SPS filed for recovery of $76 million, over 24 months, in under-collected purchased power and fuel costs through March 2021, subject to revision due to re-settlements. Of this amount, $62 million was attributed to Winter Storm Uri. In the third quarter, SPS filed a supplemental application and testimony to recover an additional $26 million in under-collected purchased power and fuel costs through June 2021 resulting primarily from SPP resettlements and continued increases in natural gas prices. The proposed recovery remains over 24 months beginning in February 2022. In October 2021, intervenors proposed a $10 million disallowance of Winter Storm Uri off-system sales margin in addition to recommending an extended recovery period. A public hearing is scheduled to begin on Nov. 1, 2021, with a final PUCT decision expected in early 2022.
	~~New Mexico~~	~~The NMPRC approved SPS' request to recover $26 million of fuel costs over 24 months with no financing charge, subject to NMPRC review.~~

~~COVID-19~~

Although the COVID-19 pandemic has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will continue to allow us to proactively manage and successfully navigate challenges, risks and uncertainties.

Continued uncertainty remains regarding COVID-19, the pace of economic recovery, any potential re-shutdowns or reinstatement of business restrictions both domestically and globally and potential workforce impacts resulting from federal laws regarding vaccinations.

~~An overview of certain risk considerations or areas which have or could significantly impact us is as follows:~~

~~Sales~~ — Xcel Energy has experienced and may continue to experience sales volatility and shifts between residential and C&I sales as a result of COVID-19. Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand small C&I electric classes), which mitigate the impact of changes to sales levels as compared to a baseline.

~~Bad Debt~~ — Bad debt expense could significantly increase due to pandemic related economic impacts, customer hardship, federal or state legislation and regulatory orders. However, several of our commissions have approved the deferral of incremental COVID-19 related costs, including bad debt expense.

~~Table of Contents~~

Xcel Energy has received orders in Colorado, Wisconsin, Texas, New Mexico, North Dakota, South Dakota and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Through the Minnesota electric rate case stay-out, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related costs. As part of the approved North Dakota electric rate case settlement agreement, the Company will not defer COVID-19 impacts. The impact related to the North Dakota natural gas utility will continue to be deferred.

In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed bad debt expense related to COVID-19 in Colorado. See Note 1 of the accompanying consolidated financial statements for further discussion.

~~The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve.~~

~~Supply Chain and Capital Expenditures~~— 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. Overall, as a result of COVID-19, manufacturing processes have experienced disruptions related to scarcity of raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, storms and labor shortages. Xcel Energy continues to monitor the availability of materials and seek alternative suppliers as necessary.


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 ~~DSM~~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, ~~2020 and in Item 2 of Xcel Energy’s Quarterly Report on~~ ~~Form 10-Q~~ ~~for the quarterly period ended March 31, 2021 and Quarterly Report on~~ ~~Form 10-~~Q ~~for the quarterly period ended June 30,~~ 2021 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings

~~Proceeding~~

Amount
(in millions)

Filing
Date

~~Approval~~

~~2020 TCR Electric Rider~~

~~$82~~

~~November 2019~~

~~Pending~~

~~2021 GUIC Natural Gas Rider~~

~~October 2020~~

~~Pending~~

~~2021 RES Electric Rider~~

~~189~~

~~November 2020~~

~~Pending~~

~~2020 North Dakota Electric Rate Case~~

~~November 2020~~

~~Received~~

~~2021 North Dakota Natural Gas Rate Case~~

~~September 2021~~

~~Pending~~

2022 Minnesota ~~Electric Rate Case~~

~~677~~

~~October 2021~~

~~Pending~~

~~2022 Minnesota Natural Gas Rate Case~~

~~TBD~~

~~November 2021~~

~~Pending~~

~~Additional Information:~~

~~2020 TCR Electric Rider —~~ ~~In November 2019, NSP-Minnesota filed the TCR Rider based on a ROE of 9.06%. An MPUC decision is pending.~~

~~2021 GUIC Natural Gas Rider —~~ ~~In October 2020, NSP-Minnesota filed the GUIC Rider based on a ROE of 9.04%. An MPUC decision is pending.~~

~~2021 RES Electric Rider —~~ In November 2020, NSP-Minnesota filed the RES Rider. The requested amount includes a true-up (2019 and 2020 riders) of $96 million and the 2021 requested amount of $93 million. The filing included a ROE of 9.06%. An MPUC decision is pending.

~~2020 North Dakota~~ Electric Rate Case —~~In November 2020,~~ In October 2021, NSP-Minnesota filed a three-year electric rate case with the ~~NDPSC seeking~~MPUC. The rate case is 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, 2022, NSP-Minnesota requested an incremental increase to interim rates of $122 million, effective Jan. 1, 2023. On Oct. 21, 2022, intervening parties to the rate case filed comments recommending the MPUC deny NSP-Minnesota’s request. A MPUC decision is expected in late 2022.

In October 2022, nine parties filed testimony. The DOC, OAG, XLI, CUB and JSC were the only parties to quantify recommended financial adjustments. XLI recommended $112 million in proposed adjustments, based on reducing ROE, reducing recovery of incentive compensation and not including the prepaid pension asset in rate base. CUB recommended adjustments based on reducing ROE. Other parties provided specific issue recommendations.

Proposed DOC modifications 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 in the rate base and rate 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:

•Rebuttal testimony: Nov. 8, 2022.

•Hearing: Dec. 13-16, 2022.

•ALJ Report: March 31, 2023.

•MPUC Order: June 30, 2023.

Table of Contents

2022 Minnesota Natural Gas Rate Case—In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of ~~$19~~$36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of ~~10.2%~~10.5%, an equity ratio of 52.5% and a rate base of ~~$677~~$934 million. In December 2021, the MPUC approved an interim rate increase of $25 million, subject to refund, effective Jan. 1, 2022.

In ~~August 2021, the NDPSC approved a settlement between~~October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following ~~effective Jan. 1, 2021:~~key terms:

•Base rate revenue increase of ~~$7 million.~~$21 million, with a true up to weather normalized actual sales for 2022.

•Revenue decoupling mechanism.

•Symmetrical property tax true-up.

•ROE of ~~9.5%~~9.57%.

•Equity ratio of 52.5%.

•~~Deferral~~A hearing is scheduled for the fourth quarter of ~~advanced grid intelligence~~2022 and ~~security initiative capital and O&M expenses.~~

•~~An earnings cap mechanism, which would return to customers 100%~~a MPUC order is expected in the first half of ~~earnings equal to or in excess of 9.75% ROE, effective until the next rate case.~~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 ~~10.49%~~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 ~~approximately $140~~$124 million. ~~NSP-Minnesota requested interim~~Interim rates of $7 million, subject to refund, ~~of $7 million to be~~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 ~~Minnesota~~South Dakota Electric Rate Case — On Oct. 25, 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The request is driven by ongoing investments in carbon free electrical generation, distribution and transmission infrastructure. The rate case is based on a requested ROE of 10.2% and a 52.50% equity ratio.

~~Table of Contents~~

~~The request is detailed as follows:~~

(Amounts in Millions, Except Percentages) 2022 2023 2024 Total
Rate request $ 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 addition, NSP-Minnesota requested interim rates, subject to refund, of $288 million to be implemented in January 2022 and an incremental $135 million to be implemented in January 2023. To mitigate the interim increase, NSP-Minnesota also proposed to continue a sales true-up for all customer classes in both 2022 and 2023. This would result in interim rates, subject to refund, of $190 million to be implemented in January 2022 and an incremental $116 million to be implemented in January 2023. A final MPUC decision on the rate case is anticipated in the second quarter of 2023.

~~2022 Minnesota Natural Gas Rate Case~~—NSP-Minnesota plans to file a request with the MPUC for an annual natural gas rate case in November 2021. As part of the request, NSP-Minnesota plans to file an option for a one-year stay-out alternative.

~~Minnesota Resource Plan~~ — In ~~July 2019,~~June 2022, NSP-Minnesota filed ~~its Minnesota resource plan, which runs through 2034.~~

~~In June~~a South Dakota electric rate case (first since 2014) seeking a revenue increase of approximately $44 million. The filing is based on a 2021 ~~NSP-Minnesota filed~~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 ~~alternative plan that would be~~equity ratio of 53%. Final rates are expected to ~~reduce carbon emissions 85% by 2030 and has a lower projected cost than either~~be effective in the first quarter of ~~the previously submitted plans. The alternative plan includes the following:~~

•~~Removing the planned Sherco combined cycle natural gas plant.~~2023.

•Retiring all coal generation by 2030 with reduced operations at some units prior to retirement, including early retirement of the A.S. King coal plant (511 MW) in 2028 and Sherco 3 coal plant (517 MW) in 2030.

•~~Extending the life of the Monticello nuclear plant from 2030 to 2040.~~

•~~Continuing to run the Prairie Island nuclear generating plant at least through current end of life (2033 and 2034).~~

•~~Adding 3,150 MW of universal solar, 2,650 MW of wind and 250 MW of storage.~~

•~~Adding 800 MW of new hydrogen-ready combustion-turbines and repowering 300 MW of blackstart combustion-turbines.~~

•~~Adding 1,900 MW of other firm dispatchable resources.~~

•~~Constructing 155 miles of transmission lines.~~

•~~Achieving 780 gigawatt hours in energy efficiency savings annually through 2034.~~

•~~Adding 400 MW of incremental demand response by 2023 and a total of 1,500 MW of demand response by 2034.~~

~~The MPUC is anticipated to make a final decision in late 2021 or early 2022.~~

~~Minnesota Relief and Recovery~~Wind Repowering — In 2020, the MPUC opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19. The status of the various proposals is listed below:

•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 20other 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 ~~wind projects under PPAs. These projects are estimated~~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 ~~save customers approximately $160 million over the next 25 years.~~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 ~~April 2021, NSP-Minnesota proposed~~September 2022, the MPUC approved NSP-Minnesota’s proposal to add 460 ~~MWs~~MW of solar facilities at the Sherco ~~site with~~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.

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 ~~incremental investment~~amount of ~~approximately $575~~$27 million. A MPUC decision is ~~expected in early 2022.~~pending.

•2021 GUIC Natural Gas Rider — In ~~June 2021,~~October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million. A MPUC ~~approved NSP-Minnesota’s proposal to acquire a 120 MW repowered wind farm from ALLETE for $210 million.~~decision is pending.

•2022 TCR Electric Rider — ~~The~~In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million. A MPUC decision is ~~also considering NSP-Minnesota’s revised proposal to provide $40 million of incremental electric vehicle rebates.~~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, ~~2020,~~2021 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, ~~2020,~~2021, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.

~~NSP-Wisconsin~~PSCo

Pending and Recently Concluded Regulatory Proceedings

~~Proceeding~~

Amount
(in millions)

Filing
Date

~~Approval~~

~~Electric and Natural Gas Settlement~~

~~$66~~

~~July 2021~~

~~Pending~~

~~Michigan Rate Case~~

~~$2.5~~

~~September 2021~~

~~Pending~~

~~Additional Information:~~

~~Wisconsin Electric and~~Colorado Natural Gas ~~Settlement~~Rate Case —In ~~July 2021, NSP-Wisconsin~~January 2022, PSCo filed a request with the ~~PSCW~~CPUC seeking ~~approval of~~ a ~~rate case settlement with various intervenors for 2022-2023.~~

~~If approved, the settlement agreement would~~net increase ~~electric rates by $35 million (4.9%) for 2022 and an incremental $18 million increase (2.5%) for 2023. For the~~to retail natural gas ~~utility,~~ rates ~~would increase by $10~~of $107 million. The total change to base rates is $215 million, ~~(8.4%) for 2022 and~~which reflects the transfer of $108 million previously recovered from customers through the pipeline system integrity adjustment rider. The request is based on a 10.25% ROE, an ~~incremental $3 million (2.3%) increase for 2023.~~

~~Key elements of the settlement include:~~

•~~ROE of 9.80% for 2022 and 10.00% for 2023.~~

•~~Equity~~equity ratio of ~~52.5% for both~~55.66% and a 2022 ~~and 2023.~~current test year with a projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022.

•~~Returning $9~~Additionally, PSCo’s request includes step revenue increases of $40 million ~~in various net regulatory liabilities~~(effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to ~~offset customer impacts in 2023.~~continued capital investment.

•~~Deferring certain pension and other post-employment benefit expense in 2021 through 2023.~~

•~~Addressing COVID-19 deferral recovery in~~In October 2022, the ~~next rate case proceeding.~~

•~~Deferring potential changes in tax expenses due to changes in federal or state tax law in 2021 through 2023.~~

•~~Incorporating an earnings sharing mechanism for 2022 and 2023.~~

~~A PSCW~~CPUC issued a written decision ~~is anticipated in the fourth quarter of 2021.~~

~~Michigan Electric Rate Case — In September 2021, NSP-Wisconsin filed a Michigan electric rate case seeking~~approving a rate increase net of ~~$2.5~~rider roll-ins of $64 million. The decision reflects a stated WACC of 6.7%, a historic test year with a year-end rate base and $16 million ~~based on~~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 using a ROE of ~~10.2%~~9.2% and an equity ratio of ~~52.5%~~53.8%. The CPUC denied the 2023-2024 step increases.

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Table of Contents

~~PSCo~~

~~Pending and Recently Concluded Regulatory Proceedings~~

~~Proceeding~~

Amount
(in millions)

Filing
Date

~~Approval~~

~~PSIA Extension~~

~~February 2021~~

~~Received~~

~~Electric Rate Case~~

~~$470~~

~~July 2021~~

~~Pending~~

~~Additional Information:~~

~~PSIA Rider Extension~~ — In February 2021, PSCo requested to extend its PSIA rider for three years (through the end of 2024), which would recover $464 million in project costs over a three-year period. The extension is intended to allow for a wind down of the rider and transition of recovery of the projects included in the rider to base rates in 2025. In October 2021, the CPUC approved a settlement agreement with CPUC Staff and the COEO to allow the rider to end at the end of 2021, transfer the investments recovered under the rider to base rates January 1, 2022, and defer $9 million of depreciation expense and return on $143 million in project costs in 2022.

Colorado ~~Electric Rate Request~~Power Pathway Settlement — In ~~July~~June 2022, the CPUC issued a final written order issuing the CPCN for the Pathway Project. Key decisions include:

•The CPUC approved PSCo’s cost estimate of $1.7 billion and recovery through the transmission rider.

•The CPUC modified the PIMs 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 mix by 2030. The CPUC deferred 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 in 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).

•Conversion of the Pawnee coal plant to natural gas by no later than Jan. 1, 2026.

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

•Addition of ~2,400 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 ~~request~~comprehensive settlement with the CPUC ~~seeking a net electric rate increase~~Staff and the Colorado Energy Office, which proposed to address four outstanding regulatory items, including recovery of ~~$343 million (or 12.4%). The total request reflects a $470 million increase, which includes $127 million of previously authorized~~fuel costs currently recovered through various rider mechanisms. The request is based on a 10.0% ROE, an equity ratio of 55.64%, a 2022 forecast test year, a rate base of $10.3 billion and impacts of a new depreciation study. A historical test year was filed with arelated to Winter Storm Uri, disputed revenue ~~deficiency of $404 million, including a 10.5% ROE. Rates are expected to be effective April 9, 2022.~~


~~Revenue Request (millions of dollars)~~	~~2022~~
~~Changes since 2019 rate case:~~
~~Plant-related growth~~	$	95
~~Advanced grid intelligence and security~~	73
~~Updated cost of capital~~	53
~~New depreciation rates~~	43
~~Wildfire mitigation~~	25
~~Property taxes~~	25
~~Amortization of previously approved deferrals~~	17
~~Other~~	12
~~Net increase to revenue~~	~~343~~
~~Roll-in of previously authorized costs:~~
~~TCA rider revenues and Cheyenne Ridge costs~~	~~127~~
~~Total base revenue request~~	$	~~470~~


~~Expected average 2022 rate base (billions of dollars)~~	$	~~10.3~~

~~2019 Electric Rate Case Appeal~~ ~~— In August 2020, PSCo filed an appeal~~associated with the ~~Denver District Court seeking a review of~~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 ~~decisions on gains and losses on sales of assets, oil and gas royalty revenues, Board of Directors equity compensation and a true-up surcharge~~approved the settlement, with an $8 million disallowance relating to ~~collect~~ the ~~difference between what rates should have been in place from February through August 2020 (based onthe CPUC’s decision on the Company’s Application for Reconsideration, Rehearing or Reargument) and what rates were actually in place. A decision is pending.~~Winter Storm Uri fuel costs.

Decoupling Filing — ~~PSCo's 2019 Electric Rate Case included~~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 April 2021, PSCo made its annual filing for 2020, and the revised tariff went into effect by operation of law on June 1, 2021. In the annual filing review, the CPUC indicated they may pursue reopening the case in order to revisit the cap. As of Sept. 30, 2021, PSCo has recognized a refund for Residential customers and a surcharge for C&I customers based on 2020 results and 2021 estimated amounts to date.

In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of decoupling. See ~~Note 1~~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 and the first, second and third quarters 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 ~~accompanying consolidated financial statements~~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 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 was legally erroneous and confiscatory to PSCo and set aside and remanded the issue for further ~~discussion.~~consideration. In October 2022, the CPUC approved PSCo’s proposed methodology to allocate gains and losses.

~~Colorado’s Power Pathway Transmission Expansion~~ 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 used 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.

SPS

Pending and Recently Concluded Regulatory Proceedings

2021 Texas Electric Rate Case — In 2021, SPS filed an electric rate case with the PUCT and its municipalities seeking an increase in base rates of approximately $140 million. In May 2022, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms:

•Base rate increase of $89 million effective retroactively to March 15, 2021.

•A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.

•Depreciation lives for Tolk accelerated to 2034 and Harrington coal assets accelerated to 2024.

In July 2022, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $85 million, substantially offset by the recognition of previously deferred costs. The impact of the retroactive amounts 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)

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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

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 the 2023 deployment schedule are currently being evaluated.

Solar Resources

In April 2022, the U.S. Department of Commerce initiated an anti-circumvention investigation that would subject CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia with potential incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports.

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

Marshall Wildfire

In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. Boulder County authorities are currently investigating the fire and have not yet determined a cause. There were no downed power lines 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 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 sharing or other mechanisms.

Inflation Reduction Act — In ~~March 2021, PSCo filed~~August 2022, the IRA was signed into law.

Key provisions impacting Xcel Energy include:

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

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

•Creates a ~~Certificate~~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 ~~Public Convenience~~customer savings over the next 5 years for existing company owned renewable projects, assuming appropriate regulatory mechanisms and ~~Necessity~~development of a market for the ~~Power Pathway transmission project, proposing a 560-mile, 345 kilovolt double circuit transmission network~~sale of credits. The IRA will drive additional customer savings as Xcel Energy adds new renewable projects due to ~~enable approximately 4,000-5,000 MW of renewable generation in eastern Colorado with an estimated cost of approximately $1.7 billion.~~

~~PSCo also presented an~~the extension of ~~the Power Pathway project into southeast Colorado, referred~~tax credits and transferability.

The IRA is expected to ~~as the May Valley - Longhorn Extension ($0.3 billion). PSCo expects future filings for related network upgrades, voltage support and interconnection facilities, which~~allow Xcel Energy to monetize tax credits more efficiently with the ~~May Valley - Longhorn Extension,~~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 ~~result in an incremental investment~~range from $0 to $200 million, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of ~~$0.5 - $1.0 billion. A CPUC decision regarding~~ the ~~Power Pathway project,~~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 ~~May Valley - Longhorn Extension, is expected by February 2022.~~

~~KEPCO Filing~~ —~~In September 2020, PSCo filed with~~availability of renewable generation. The cold weather also affected the ~~CPUC~~country’s supply and demand for ~~approval~~natural gas. These factors contributed to ~~terminate~~extremely high market prices for natural gas and electricity. As a ~~solar PPA with KEPCO Solar~~result of ~~Alamosa, Inc.~~the extremely high market prices, Xcel Energy incurred net natural gas, fuel and ~~establish a regulatory asset to recover transaction~~purchased energy costs of approximately ~~$41 million. However, the ALJ ruled against approval of the Termination Agreement. In July 2021, the CPUC upheld the ALJ’s recommended decision.~~

~~Electric Resource Plan~~ —In March 2021, PSCo filed its 2021 Electric Resource Plan with the CPUC. The filing outlines the proposed future retirements/conversions of PSCo’s remaining coal plants and is expected to result in an 80% renewable fuel mix and an 85% carbon emissions reduction target by 2030 (from 2005 levels).

~~Major components of PSCo's proposed preferred plan include:~~

•~~Early retirement of Comanche Generating Station: Unit 3 in 2040 (currently 2070).~~

•~~Early retirement of Hayden Generating Station: Unit 1 in 2028 (currently 2030); Unit 2 in 2027 (currently 2036).~~

•~~Conversion of Pawnee Generating Station from coal to natural gas in 2028 with retirement in 2041.~~

•~~2,300 MW of wind power.~~

•~~1,600 MW of large-scale solar power.~~

•~~400 MW of energy storage.~~

•~~1,300 MW of flexible dispatchable resources (including natural gas).~~

~~The preferred plan proposes to create a~~$1 billion (largely deferred as regulatory asset to recover costs over their original depreciation lives for the Hayden power plant and the coal handling equipment at Pawnee. It also proposes the use of securitization to finance and recover the remaining book value and decommissioning costs for Comanche Unit 3 upon retirement in 2040.assets).

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~~In October 2021, intervenors filed varying proposals related to Comanche Unit 3’s retirement date~~Xcel Energy has received recovery approval from all of our impacted states except for Texas, which is pending. A summary of pending and ~~commencement of Comanche Unit 3 reduced operations.~~

~~A CPUC decision on the resource plan~~recently approved regulatory requests for Winter Storm Uri cost recovery is expected in the first quarter of 2022 with the competitive solicitation for resource additions expected in the second quarter 2022. Incremental generation system costs to meet carbon emission reduction targets are proposed to be recovered through a Clean Energy Plan Rider.

~~PSCo~~ — ~~Comanche Unit 3~~ — PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up, the unit experienced a loss of turbine oil, which damaged the unit. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo incurred replacement power costs of approximately $16 million during the outage.

In October 2020, the CPUC initiated a review of Comanche Unit 3’s performance. In March 2021, the CPUC Staff issued a report, which noted higher-than average outages and included criticisms of PSCo’s operations of Comanche Unit 3 over the last ten years. The report recommended thorough explanation of the future of Comanche Unit 3 operations in the next resource plan, performance standards for all company-owned generation and a review of outage and repair costs in the upcoming proceedings.

In October 2021, a comprehensive settlement on several regulatory issues was reached, which also addressed treatment of Comanche Unit 3 replacement power costs. See Note 1 of the accompanying consolidated financial statements for further discussion.

~~SPS~~

~~Pending and Recently Concluded Regulatory Proceedings~~listed below.

~~Proceeding~~Utility Subsidiary

Jurisdiction

Amount
(in millions)

Filing
Date

~~Approval~~Regulatory Status

~~2021 New Mexico Electric Rate Case~~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

~~$62~~Colorado

~~June~~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.

~~Pending~~
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.

~~2021 Texas Electric Rate Case~~SPS

~~$140~~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.

~~February 2021~~

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.

~~Pending~~

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.

~~Additional Information:~~

~~2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC with a current requested base rate increase of approximately $84 million.~~

The request was based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%, an equity ratio of 54.72% and a retail rate base of approximately $1.9 billion.

~~In June 2021, SPS and various parties filed an uncontested comprehensive stipulation, which includes:~~

•~~Base rate revenue increase of $62 million.~~

•~~ROE of 9.35% for purposes of filings related to (1) the Hale and Sagamore wind projects; and (2) reconciliation of the settlement revenue requirement.~~

•~~Equity ratio of 54.72%.~~

•~~Increase in depreciation expense of $6 million. This includes a change in the depreciable lives of the Tolk power plant to 2032 and coal handling assets at the Harrington facility to 2024.~~

~~The stipulation is subject to NMPRC approval. A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.~~

~~2021 Texas Electric Rate Case~~— In February 2021, SPS filed an electric rate case with the PUCT and its municipalities. The current request is seeking an increase in base rates of approximately $140 million. SPS’ net rate increase to Texas customers is expected to be approximately $71 million, or 9.2%, as a result of the offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.

~~The request is based on a ROE of 10.35%, an equity ratio of 54.60%, a rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020.~~

The request includes the effect of losing approximately 400 MW from a wholesale transmission customer and changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032) and coal handling assets at the Harrington facility (to 2024).

~~In October 2021, the scheduled hearings were abated to continue progress on a potential rate case settlement between SPS and various intervenors.~~

~~Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2022.~~

Environmental

~~Affordable~~ Clean ~~Energy~~Air Act

In ~~July 2019,~~April 2022 the EPA ~~adopted~~proposed regulations under the ~~Affordable~~"Good Neighbor" provisions of the Clean Air Act. The proposed rules establish an allowance trading program for NOx, potentially impacting Xcel Energy ~~rule, which requires states~~generating facilities in Minnesota, Texas and Wisconsin. Facilities without NOx controls will have to secure additional allowances, install NOx controls, or develop ~~plans by 2022 for greenhouse gas reductions from coal-fired power plants. In January 2021,~~a strategy of operations that utilizes the ~~U.S. Court of Appeals~~existing allowance allocations. The EPA has indicated that it intends for the ~~D.C. Circuit issued a decision vacating and remanding~~rule to be final by the ~~Affordable Clean Energy rule. That decision would allow~~end of 2022 with initial applicability for 2023. While the ~~EPA to proceed with alternate~~financial impacts of the proposed regulation ~~of coal-fired power plants. If the new rules require additional investment,~~are uncertain, Xcel Energy ~~believes~~anticipates that ~~the cost of these initiatives or replacement generation would~~costs will be recoverable through ~~rates based on prior state commission practices.~~regulatory mechanisms.

~~Emerging Regulation~~

~~New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas.~~

CERCLA

PFAS are man-made chemicals ~~found~~that are widely used in ~~many~~ consumer products ~~that~~and can persist and ~~accumulate~~bio-accumulate in the environment. ~~These chemicals have received heightened attention by environmental regulators. Increased regulation~~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 ~~other emerging contaminants at~~perfluorooctanesulfonic acid. This proposed rule could result in new obligations for investigation and cleanup wherever PFAS are found to be present. The impact the ~~federal, state,~~proposed regulation may have on electric and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. Xcel Energy will continue to monitor these regulatory developments and their potential impact on its operations.


~~Potential Tax Reform~~

~~The U.S. Congress~~gas utilities is currently discussing potential proposals that may impact federal tax law. Proposals are being made in conjunction with a bipartisan infrastructure bill and a larger reconciliation package. At this time, it is unknown what, if any, changes may ultimately occur. If the tax laws were changed and there was an increase in the federal tax rate, Xcel Energy would expect to defer the impact and ultimately recover the incremental tax expense from our customers consistent with precedent in the federal tax law change in 2017. As a result, we would not expect the impact of a change in the tax rate to have a material impact on our earnings.

uncertain.

~~Table of Contents~~


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 of 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 the contracts underlying ~~its~~our derivatives, the contracts expose us to some credit and non-performance risk.

Distress in the financial markets may impact counterparty risk, 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.

Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

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

Fair value of net commodity trading contracts as of Sept. 30, ~~2021:~~2022:


		Futures / Forwards Maturity											Futures / Forwards Maturity
(Millions of Dollars)	(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	NSP-Minnesota (a)	$	(8)	$	(7)	$	(1)	$	(1)	$	(17)	NSP-Minnesota (a)	$	(8)	$	(11)	$	(6)	$	(3)	$	(28)
NSP- Minnesota (b)	NSP- Minnesota (b)	2		7		(6)		2		5		NSP- Minnesota (b)	6		4		(1)		(2)		7
PSCo (a)	PSCo (a)	10		8		1		1		20		PSCo (a)	17		7		3		1		28
PSCo (b)	PSCo (b)	(30)		(43)		(4)		—		(77)		PSCo (b)	(50)		(21)		1		—		(70)
		$	(26)	$	(35)	$	(10)	$	2	$	(69)		$	(35)	$	(21)	$	(3)	$	(4)	$	(63)

Options Maturity
(Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value
NSP-Minnesota (b)
$ 1 $ — $ — $ 4 $ 5
PSCo (b)
25 22 — — 47
$ 26 $ 22 $ — $ 4 $ 52

Table of Contents


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

(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)	2021		2020		(Millions of Dollars)	2022		2021
Fair value of commodity trading net contracts outstanding at Jan. 1	Fair value of commodity trading net contracts outstanding at Jan. 1	$	(54)	$	(59)	Fair value of commodity trading net contracts outstanding at Jan. 1	$	(33)	$	(54)
Contracts realized or settled during the period	Contracts realized or settled during the period	(35)		(9)		Contracts realized or settled during the period	(11)		(35)
Commodity trading contract additions and changes during the period	Commodity trading contract additions and changes during the period	72		10		Commodity trading contract additions and changes during the period	31		72
Fair value of commodity trading net contracts outstanding at Sept. 30	Fair value of commodity trading net contracts outstanding at Sept. 30	$	(17)	$	(58)	Fair value of commodity trading net contracts outstanding at Sept. 30	$	(13)	$	(17)

At Sept. 30, 2022, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately $9 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $9 million. At Sept. 30, 2021, a 10% increase in market prices for commodity trading contracts ~~through the forward curve~~ 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. At Sept. 30, 2020, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $14 million. 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 onof 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, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

(Millions of Dollars) Three Months Ended Sept. 30 VaR Limit Average High Low
2021 $ 1.9 $ 3.0 $ 1.5 $ 2.2 $ 0.9
2020 1.2 3.0 1.0 1.3 0.8

A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this widespread weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.


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

Nuclear Fuel Supply — NSP-Minnesota has contracted for ~~approximately~~ ~~23% o~~fand has its ~~2021~~2022 and 2023 enriched nuclear material requirements ~~from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impact~~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 supplied from Russia. Long-term, through 2030,~~material. NSP-Minnesota is scheduled to take delivery of ~~approximate~~lyapproximately 30% of its average enriched nuclear material requirements from these sources. NSP-Minnesota is able to manage nuclear fuel supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.Russia through 2030.

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.

At Sept. 30, ~~2021~~2022 and ~~2020,~~2021, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pre-tax interest expense annually by approximately ~~$18~~$3 million and $6$18 million, respectively.

~~Table of Contents~~

See Note 8 to the consolidated financial statements for a discussion of Xcel ~~Energy Inc. and its subsidiaries’~~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.

Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.

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 ~~monitor~~monitors these policies to reflect changes and scope of operations.

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. At Sept. 30, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $29 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $3 million.

Xcel Energy conducts credit reviews for all counterparties and employs credit risk ~~control,~~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

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, are reported at fair value.

The Company’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, ~~2021.~~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, ~~2021.~~2022.

Table of Contents


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Operating Cash Flows


(Millions of Dollars)	Nine Months Ended Sept. 30
Cash provided by operating activities — ~~2020~~2021	$	~~2,174~~1,579

Components of change — ~~2021~~2022 vs. ~~2020~~2021
Higher net income	9775
Non-cash transactions ~~(a)~~	69159
Changes in working capital ~~(b)~~	~~111~~ (79)
Changes in net regulatory and other assets and liabilities	~~(872)~~1,433
Cash provided by operating activities — ~~2021~~2022	$	~~1,579~~3,167

~~(a)~~Non-cash transactions applicable to net income (e.g., depreciation and amortization, nuclear fuel amortization, changes in deferred income taxes, allowance for equity funds used during construction, etc.).

~~(b)Working capital includes accounts receivable, accrued unbilled revenues, inventories, accounts payable, other current assets and other current liabilities.~~

Net cash provided by operating activities ~~decreased $595~~increased $1,588 million for the nine months ended Sept. 30, ~~2021~~2022 compared with the prior year. The ~~decrease~~increase was primarily due to the ~~deferral of~~ net natural gas, fuel and purchased energy costs related to Winter Storm Uri (incurred/deferred) in the first ~~quarter.~~quarter of 2021.

Investing Cash Flows


(Millions of Dollars)	Nine Months Ended Sept. 30
Cash used in investing activities — ~~2020~~2021	$	~~(3,021)~~(3,065)

Components of change — ~~2021~~2022 vs. ~~2020~~2021
~~Decreased~~Increased capital expenditures	~~649~~ (293)
~~Sale of MEC in 2020~~	~~(684)~~
Other investing activities	~~(9)~~37
Cash used in investing activities — ~~2021~~2022	$	~~(3,065)~~(3,321)

Net cash used in investing activities increased ~~$44~~$256 million for the nine months ended Sept. 30, ~~2021~~2022 compared with the prior year. The ~~decrease~~increase in capital expenditures was ~~primarily~~largely due to ~~the purchase of MEC in January 2020, which was subsequently sold in July 2020.~~timing and normal/planned system expansion.

Financing Cash Flows


(Millions of Dollars)	Nine Months Ended Sept. 30
Cash provided by financing activities — ~~2020~~2021	$	~~1,484~~1,988

Components of change — ~~2021~~2022 vs. ~~2020~~2021
Higher net short-term debt ~~issuances~~repayments	~~238~~
~~Lower repayments of long-term debt~~	~~302~~ (2,010)
Higher ~~dividends paid to shareholders~~long-term debt issuances, net of repayments	~~(60)~~43
Higher proceeds from issuance of common stock	143

Other financing activities	24 (59)
Cash provided by financing activities — ~~2021~~2022	$	~~1,988~~105

Net cash provided by financing activities ~~increased $504~~decreased $1,883 million for the nine months ended Sept. 30, ~~2021~~2022 compared with the prior year. The ~~increase~~decrease was primarily ~~attributable~~related to the amount/timing of debt issuances and repayments ~~partially attributable to~~associated with Winter Storm Uri.

~~Table of Contents~~

Capital Requirements

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

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

•In January ~~2021,~~2022, contributions of ~~$125~~$50 million were made across four of Xcel Energy’s pension plans.

•In ~~2020,~~2021, contributions of ~~$150~~$131 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 ~~the~~their revolving credit facility termination date for two additional one-year periods beyond the ~~June 2024~~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. ~~26, 2021, Xcel~~25, 2022, 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.	$	1,250	$	427	$	823	$	—	$	823	Xcel Energy Inc.	$	1,500	$	129	$	1,371	$	1	$	1,372
PSCo	PSCo	700		8		692		7		699		PSCo	700		264		436		3		439
NSP-Minnesota	NSP-Minnesota	500		9		491		258		749		NSP-Minnesota	700		55		645		4		649
SPS	SPS	500		55		445		2		447		SPS	500		67		433		1		434
NSP-Wisconsin	NSP-Wisconsin	150		—		150		3		153		NSP-Wisconsin	150		—		150		3		153
Total	Total	$	3,100	$	499	$	2,601	$	270	$	2,871	Total	$	3,550	$	515	$	3,035	$	12	$	3,047

(a)Credit facilities expire in ~~June 2024.~~September 2027.

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

Bilateral Credit Agreement

In April ~~2021,~~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, ~~2021, NSP-Minnesota’s~~2022, NSP-Minnesota had $50 million of outstanding letters of credit under the $75 million bilateral credit ~~agreement were as follows:~~agreement.

(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75 $ 41 $ 34

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

•$~~1.25~~1.5 billion for Xcel Energy Inc.

•$700 million for PSCo.

•$~~500~~700 million for NSP-Minnesota.

•$500 million for SPS.

•$150 million for NSP-Wisconsin.

~~In addition, in February 2021, Xcel Energy Inc. entered into a $1.2 billion 364-Day Term Loan Agreement that matures Feb. 17, 2022. Xcel Energy has an option to extend through Feb. 16, 2023.~~

Table of Contents

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


(Amounts in Millions, Except Interest Rates)	(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2021			Year Ended Dec. 31, 2020			(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2022			Year Ended Dec. 31, 2021
Borrowing limit	Borrowing limit	$	4,300		$	3,100		Borrowing limit	$	3,550		$	3,100
Amount outstanding at period end	Amount outstanding at period end	1,747			584			Amount outstanding at period end	158			1,005
Average amount outstanding	Average amount outstanding	1,742			1,126			Average amount outstanding	187			1,399
Maximum amount outstanding	Maximum amount outstanding	1,857			2,080			Maximum amount outstanding	329			2,054
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	0.57		%	1.45		%	Weighted average interest rate, computed on a daily basis	2.51		%	0.57		%
Weighted average interest rate at period end	Weighted average interest rate at period end	0.56			0.23			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 ~~Inc.~~ 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 Inc.~~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 ~~2022~~2023 through ~~2026~~2027 are as follows:

Base Capital Forecast (Millions of Dollars)
By Regulated Utility 2022 2023 2024 2025 2026 2022 - 2026 Total
PSCo $ 1,930 $ 1,850 $ 2,070 $ 2,220 $ 1,860 $ 9,930
NSP-Minnesota 2,250 2,030 1,830 2,130 2,010 10,250
SPS 630 660 690 780 790 3,550
NSP-Wisconsin 480 420 540 460 390 2,290
Other (a)
(10) — 10 (30) 10 (20)
Total base capital expenditures $ 5,280 $ 4,960 $ 5,140 $ 5,560 $ 5,060 $ 26,000

Base Capital Forecast (Millions of Dollars)
By Function 2022 2023 2024 2025 2026 2022 - 2026 Total
Electric distribution $ 1,485 $ 1,600 $ 1,520 $ 1,605 $ 1,720 $ 7,930
Electric transmission 1,105 1,220 1,575 1,965 1,555 7,420
Electric generation 645 580 670 650 650 3,195
Natural gas 655 670 695 660 660 3,340
Other 725 545 450 340 450 2,510
Renewables 665 345 230 340 25 1,605
Total base capital expenditures $ 5,280 $ 4,960 $ 5,140 $ 5,560 $ 5,060 $ 26,000


	Base Capital Forecast (Millions of Dollars)
By Regulated Utility	2023		2024		2025		2026		2027		2023 - 2027 Total
PSCo	$	2,140	$	2,440	$	2,550	$	1,980	$	2,190	$	11,300
NSP-Minnesota	2,000		2,400		2,530		2,200		2,580		11,710
SPS	710		780		720		770		900		3,880
NSP-Wisconsin	540		570		500		450		540		2,600
Other (a)	10		10		(30)		10		10		10
Total base capital expenditures	$	5,400	$	6,200	$	6,270	$	5,410	$	6,220	$	29,500

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


	Base Capital Forecast (Millions of Dollars)
By Function	2023		2024		2025		2026		2027		2023 - 2027 Total
Electric distribution	$	1,610	$	1,790	$	1,680	$	2,000	$	2,450	$	9,530
Electric transmission	1,280		1,650		1,890		1,690		1,900		8,410
Electric generation	710		910		900		560		650		3,730
Natural gas	740		730		760		650		680		3,560
Other	780		840		570		510		540		3,240
Renewables	280		280		470		—		—		1,030
Total base capital expenditures	$	5,400	$	6,200	$	6,270	$	5,410	$	6,220	$	29,500

~~Table of Contents~~

The five-year capital forecast includes the proposed Colorado Pathway transmission expansion (approximately $1.7 billion), the proposed 460 MW Sherco solar facility (approximately $600 million) and the approved ALLETE wind repowering (approximately $210 million).

~~Additional capital investment in~~base plan does not include any potential renewable generation assets approved in our Minnesota and Colorado resource plans or additional transmission ~~may be~~capital needed to integrate new renewable generation additions in Colorado, beyond the Pathway project. We expect further clarification in the ~~five-year forecast pending approval~~second half of ~~regulatory filings in Minnesota and Colorado. The approval of~~2023 after the ~~proposed~~commissions rule on the recommended resource ~~plans~~plan portfolios, which could result in upincremental capital expenditures of approximately $2 to ~~2,000 MW~~$4 billion (assuming 50% ownership of renewable ~~generation being needed between 2024 - 2026, resulting in potential capital expenditures estimated between $1.0 to $1.5 billion (assuming Xcel Energy were to own ~50% of the renewables)~~projects). Additionally, the associated $0.5 billion to $1.0 billion of network upgrades, voltage support and interconnection work related to the Colorado Power Pathway could also be needed during this five-year forecast depending on resource mix, location and timing. Any additional capital investment would likely be funded with approximately 50% equity and 50% 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.

Financing for Capital Expenditures through ~~2026~~2027 — 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 ~~2022~~2023 through ~~2026:~~2027 (includes the impact of approximately $1.8 billion of tax credit transferability):


(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)	$	~~17,640~~20,540
New debt (b)	~~7,110~~8,210
Equity through the DRIP and benefit program	~~450~~425
Other equity	~~800~~325
Base capital expenditures ~~2022-2026~~2023-2027	$	~~26,000~~29,500

Maturing Debt	$	~~3,900~~3,800

(a)Net of dividends and pension funding.

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

~~2021~~2022 Planned Financing Activity — During ~~2021,~~2022, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit ~~programs~~.programs. In ~~addition, Xcel Energy may issue $800~~2022, approximately $150 million inof equity ~~under~~has been issued through an at-the-market program. Xcel Energy ~~Inc.~~ and its utility subsidiaries issued ~~or plan to issue~~ the ~~following:~~following long-term debt:

Issuer

Security

Amount

Status

Tenor

Coupon

Issuer

Security

Amount

Tenor

Coupon

Xcel Energy

Unsecured Bonds

800

million

2021 Q4

5 Year/10 Year

TBD

Xcel Energy

Unsecured Senior Notes

700

million

10 Year

4.60%

PSCo

First Mortgage Bonds

750

million

Completed

10 Year

1.88

PSCo

First Mortgage Bonds

300

million

10 Year

4.10%

PSCo

First Mortgage Bonds

400

million

30 Year

4.50%

SPS

First Mortgage Bonds

250

million

Completed

29 Year

3.15

SPS

First Mortgage Bonds

200

million

30 Year

5.15%

NSP-Minnesota

First Mortgage Bonds

425

million

Completed

10 Year

2.25

NSP-Minnesota

First Mortgage Bonds

500

million

30 Year

4.50%

NSP-Minnesota

First Mortgage Bonds

425

million

Completed

31 Year

3.20

NSP-Wisconsin

First Mortgage Bonds

100

million

Completed

30 Year

2.82

NSP-Wisconsin

First Mortgage Bonds

100

million

30 Year

4.86%

Financing plans are subject to change, depending on legislative initiatives (e.g., federal tax law changes), capital expenditures, 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 ~~2021~~2022 Earnings Guidance — — Xcel ~~Energy narrows 2021~~Energy’s 2022 GAAP and ongoing earnings guidance is a narrowed range of $3.14 to ~~$2.94 to $2.98 from $2.90 to $3.00~~$3.19 per share.(a)

Key assumptions as compared with ~~2020~~2021 levels unless noted:

•Constructive outcomes in all rate case and regulatory proceedings.

•~~Modest impacts from COVID-19.~~

•Normal weather patterns for the remainder of the year.

•Weather-normalized retail electric sales are projected to increase ~~~1.5 to 2%~~~2%.

•Weather-normalized retail firm natural gas sales are projected to increase ~~~1 to 2%~~~1%.

•Capital rider revenue is projected to ~~increase $100 million to $110 million~~be relatively flat (net of PTCs). ~~PTCs are credited~~The reduction in capital rider revenue is due to ~~customers, through capital riders, fuel clause or base rates~~changes in expected PTC levels and ~~results in a reduction to electric margin.~~is largely earnings neutral.

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

•Depreciation expense is projected to increase approximately ~~$170~~$295 million to ~~$180~~$305 million.

•Property taxes are projected to increase approximately ~~$25~~$35 million to ~~$35~~$45 million.

•Interest expense (net of AFUDC - debt) is projected to increase ~~$20~~$100 million to ~~$30~~$110 million.

•AFUDC - equity is projected to ~~decline approximately $40 million to $50 million.~~be relatively flat.

•ETR is projected to be ~~(4%~~~(7%) to ~~(5%~~(9%). ~~The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.~~

~~Table of Contents~~

Xcel Energy ~~2022~~2023 Earnings Guidance — Xcel Energy’s ~~2022~~2023 GAAP and ongoing earnings guidance is a range of ~~$3.10~~$3.30 to ~~$3.20~~$3.40 per share.(a)

Key assumptions as compared with ~~2021~~2022 projected levels unless noted:

•Constructive outcomes in all rate case and regulatory proceedings.

•Normal weather patterns for the year.

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

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

•Capital rider revenue is projected to increase ~~$30~~$70 million to ~~$40~~$80 million (net of PTCs). ~~PTCs are credited to customers, through capital riders and reductions to electric margin.~~

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

•Depreciation expense is projected to increase approximately ~~$260~~$140 million to ~~$270~~$150 million.

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

•Interest expense (net of AFUDC - debt) is projected to increase ~~$45~~$110 million to ~~$55~~$120 million.

•AFUDC - equity is projected to ~~be relatively flat.~~increase $0 million to $10 million.

•ETR is projected to be ~(5%) to ~~(6%~~(7%). ~~The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.~~

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

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

•Deliver long-term annual EPS growth of 5% to 7% based off of a ~~2021~~2022 base of ~~$2.96~~$3.15 per share, which represents the mid-point of the ~~revised 2021~~original 2022 guidance range of ~~$2.94~~$3.10 to ~~$2.98~~$3.20 per share.

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

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

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


ITEM 3 — QUANTITATIVE 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, ~~2020~~2021 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, ~~2021,~~2022, 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, ~~2020,~~2021, 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 ~~Purchasers~~Purchaser:

For the quarter endedSept. 30, ~~2021,~~ 2022, 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.

~~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 on April 3, 2020	Xcel Energy Inc Form 8-K dated April 3, 2020	3.01
4.014.01	Supplemental Indenture dated as of July ~~19, 2021~~15, 2022 between Northern States Power Company and U.S. Bank Trust Company, National Association, as successor Trustee, creating ~~2.82%~~4.86% First Mortgage Bonds, Series due ~~May 1, 2051~~September 15, 2052	NSP-Wisconsin Form 8-K dated July ~~20, 2021~~15, 2022	4.01
10.01*	~~Summary of Non-Employee Director Compensation, effective~~Fourth Amended and Restated Credit Agreement, dated as of ~~October 1, 2021~~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.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

3634

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.

~~October 28, 2021~~10/27/2022	By:	~~/s/ JEFFREY S. SAVAGE~~
		~~Jeffrey S. Savage~~
		~~Senior Vice President, Controller~~
		~~(Principal Accounting Officer)~~

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

3735


(Millions of Dollars)	Limit		Amount Used		Available
Xcel Energy Inc.	$	1,200	$	1,200	$	—


(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	41	$	34


(Millions of Dollars)	Three Months Ended Sept. 30, 2021 vs. 2020		Nine Months Ended Sept. 30, 2021 vs. 2020
Non-fuel riders	$	59	$	196
Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota)	30		106
Proprietary commodity trading, net of sharing (a)	11		49

Sales and demand (b)	10		20

Estimated impact of weather (net of decoupling/sales true-up)	(8)		(3)

Texas 2019 rate case surcharge (c)	(70)		(70)
PTCs flowed back to customers (offset by lower ETR)	(31)		(111)
Other (net)	5		(6)
Total increase in electric margin	$	6	$	181


(Millions of Dollars)	Three Months Ended Sept. 30		VaR Limit		Average		High		Low
2021	$	1.9	$	3.0	$	1.5	$	2.2	$	0.9
2020	1.2		3.0		1.0		1.3		0.8