UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended ~~June 30, 2021~~March 31, 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)

~~(Commission File Number)~~

(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 ~~July 22, 2021~~April 21, 2022
Common Stock, $2.50 par value						~~538,436,651~~544,653,284 shares

TABLE OF CONTENTS


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	4
	Consolidated Statements of Income	4
	Consolidated Statements of Comprehensive Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Balance Sheets	78
	Consolidated Statements of Common Stockholders’ Equity	87
	Notes to Consolidated Financial Statements	9
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2219
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	3430
Item 4 —	Controls and Procedures	3430

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	3430
Item 1A —	Risk Factors	3430
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	3431
Item 6 —	Exhibits	3531

SIGNATURES		3632

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available on various filings with the Securities and Exchange Commission.

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-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
~~WGI~~			~~West Gas Interstate~~
WYCO			WYCO Development, LLC
Xcel Energy			Xcel Energy Inc. and its subsidiaries


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


Electric, Purchased Gas and Resource Adjustment Clauses
~~DSM~~			~~Demand side management~~
~~FCA~~			~~Fuel clause 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~~BART			~~FASB Accounting Standards Codification~~Best available retrofit technology
C&I			Commercial and Industrial
CCR			Coal combustion residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD			Cooling degree-days
CEO			Chief executive officer
CFO			Chief financial officer
CORE			CORE Electric Cooperative
COVID-19			Novel coronavirus
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
~~IRP~~			~~Integrated Resource Plan~~
~~ISO~~			~~Independent System Operator~~
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
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
~~PFAS~~			~~Per- and PolyFluoroAlkyl Substances~~


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
VaR			Value at Risk
~~VIE~~			~~Variable interest entity~~


Measurements
MW			Megawatts


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to ~~2021~~2022 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 ~~impacts~~impact on our results of operations, financial condition and cash flows orof resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed ~~elsewhere~~ in ~~this Quarterly Report on Form 10-Q and in other filings with the SEC (including~~ Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2020,~~2021 and subsequent ~~filings),~~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 Code of Conduct; ability to recover ~~costs;~~costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures ~~and~~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; and regulatory changes and/or limitations related to the use of natural gas as an energy source.

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 June 30				Six Months Ended June 30					Three Months Ended March 31
		2021		2020		2021		2020			2022		2021
Operating revenues	Operating revenues									Operating revenues
Electric	Electric	$	2,597	$	2,286	$	5,467	$	4,489	Electric	$	2,633	$	2,870
Natural gas	Natural gas	449		280		1,096		863		Natural gas	1,090		647
Other	Other	22		20		46		45		Other	28		24
Total operating revenues	Total operating revenues	3,068		2,586		6,609		5,397		Total operating revenues	3,751		3,541

Operating expenses	Operating expenses									Operating expenses
Electric fuel and purchased power	Electric fuel and purchased power	1,047		833		2,433		1,630		Electric fuel and purchased power	1,094		1,386
Cost of natural gas sold and transported	Cost of natural gas sold and transported	218		86		517		371		Cost of natural gas sold and transported	710		299
Cost of sales — other	Cost of sales — other	9		8		17		17		Cost of sales — other	10		8
Operating and maintenance expenses	Operating and maintenance expenses	600		550		1,184		1,129		Operating and maintenance expenses	602		584
Conservation and demand side management expenses	Conservation and demand side management expenses	71		68		144		142		Conservation and demand side management expenses	92		73
Depreciation and amortization	Depreciation and amortization	528		473		1,049		936		Depreciation and amortization	562		521
Taxes (other than income taxes)	Taxes (other than income taxes)	157		146		320		295		Taxes (other than income taxes)	171		163
Total operating expenses	Total operating expenses	2,630		2,164		5,664		4,520		Total operating expenses	3,241		3,034

Operating income	Operating income	438		422		945		877		Operating income	510		507

Other income (expense), net		3		5		8		(7)
Other income, net										Other income, net	1		5
Earnings from equity method investments	Earnings from equity method investments	20		6		34		17		Earnings from equity method investments	15		14
Allowance for funds used during construction — equity	Allowance for funds used during construction — equity	18		37		32		61		Allowance for funds used during construction — equity	13		14

Interest charges and financing costs	Interest charges and financing costs									Interest charges and financing costs
Interest charges — includes other financing costs of $7, $7, $14 and $14, respectively		212		208		417		407
Interest charges — includes other financing costs of $8 and $7, respectively										Interest charges — includes other financing costs of $8 and $7, respectively	214		205
Allowance for funds used during construction — debt	Allowance for funds used during construction — debt	(6)		(12)		(11)		(22)		Allowance for funds used during construction — debt	(5)		(5)
Total interest charges and financing costs	Total interest charges and financing costs	206		196		406		385		Total interest charges and financing costs	209		200

Income before income taxes	Income before income taxes	273		274		613		563		Income before income taxes	330		340
Income tax benefit	Income tax benefit	(38)		(13)		(60)		(19)		Income tax benefit	(50)		(22)
Net income	Net income	$	311	$	287	$	673	$	582	Net income	$	380	$	362

Weighted average common shares outstanding:	Weighted average common shares outstanding:									Weighted average common shares outstanding:
Basic	Basic	539		527		539		526		Basic	545		538
Diluted	Diluted	539		527		539		527		Diluted	545		539

Earnings per average common share:	Earnings per average common share:									Earnings per average common share:
Basic	Basic	$	0.58	$	0.54	$	1.25	$	1.10	Basic	$	0.70	$	0.67
Diluted	Diluted	0.58		0.54		1.25		1.10		Diluted	0.70		0.67

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 June 30				Six Months Ended June 30					Three Months Ended March 31
		2021		2020		2021		2020			2022		2021
Net income	Net income	$	311	$	287	$	673	$	582	Net income	$	380	$	362
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 $0, $1, $1 and $1, respectively		1		2		1		3
Reclassifications of loss to net income, net of tax of $1 and $—, respectively										Reclassifications of loss to net income, net of tax of $1 and $—, respectively	1		—
Derivative instruments:	Derivative instruments:									Derivative instruments:
Net fair value increase (decrease), net of tax of $0, $0, $0 and $(3), respectively		0		0		0		(10)
Reclassification of losses to net income, net of tax of $0, $1, $1 and $1, respectively		2		1		5		3
Net fair value increase, net of tax of $1 and $—, respectively										Net fair value increase, net of tax of $1 and $—, respectively	5		—
Reclassification of losses to net income, net of tax of $1 and $1, respectively										Reclassification of losses to net income, net of tax of $1 and $1, respectively	1		3

Total other comprehensive income (loss)		3		3		6		(4)
Total other comprehensive income										Total other comprehensive income	7		3
Total comprehensive income	Total comprehensive income	$	314	$	290	$	679	$	578	Total comprehensive income	$	387	$	365

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)


		Six Months Ended June 30					Three Months Ended March 31
		2021		2020			2022		2021
Operating activities	Operating activities					Operating activities
Net income	Net income	$	673	$	582	Net income	$	380	$	362
Adjustments to reconcile net income to cash provided by operating activities:
Adjustments to reconcile net income to cash provided by (used in) operating activities:						Adjustments to reconcile net income to cash provided by (used in) operating activities:
Depreciation and amortization	Depreciation and amortization	1,043		942		Depreciation and amortization	567		517
Nuclear fuel amortization	Nuclear fuel amortization	56		65		Nuclear fuel amortization	30		30
Deferred income taxes	Deferred income taxes	(67)		0		Deferred income taxes	(55)		(23)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(32)		(61)		Allowance for equity funds used during construction	(13)		(14)
Earnings from equity method investments	Earnings from equity method investments	(34)		(17)		Earnings from equity method investments	(15)		(14)
Dividends from equity method investments	Dividends from equity method investments	21		21		Dividends from equity method investments	10		11
Provision for bad debts	Provision for bad debts	27		26		Provision for bad debts	17		14
Share-based compensation expense	Share-based compensation expense	21		41		Share-based compensation expense	4		9
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	(63)		19		Accounts receivable	(191)		(57)
Accrued unbilled revenues	Accrued unbilled revenues	14		97		Accrued unbilled revenues	146		123
Inventories	Inventories	7		15		Inventories	107		39
Other current assets	Other current assets	24		7		Other current assets	(10)		8
Accounts payable	Accounts payable	(15)		(160)		Accounts payable	(34)		(21)
Net regulatory assets and liabilities	Net regulatory assets and liabilities	(794)		12		Net regulatory assets and liabilities	215		(961)
Other current liabilities	Other current liabilities	(265)		(241)		Other current liabilities	51		13
Pension and other employee benefit obligations	Pension and other employee benefit obligations	(128)		(146)		Pension and other employee benefit obligations	(31)		(132)
Other, net	Other, net	1		(54)		Other, net	(38)		(40)
Net cash provided by operating activities		489		1,148
Net cash provided by (used in) operating activities						Net cash provided by (used in) operating activities	1,140		(136)

Investing activities	Investing activities					Investing activities
Capital/construction expenditures	Capital/construction expenditures	(1,967)		(2,569)		Capital/construction expenditures	(942)		(1,024)
Purchase of investment securities	Purchase of investment securities	(628)		(1,160)		Purchase of investment securities	(156)		(199)
Proceeds from the sale of investment securities	Proceeds from the sale of investment securities	410		1,150		Proceeds from the sale of investment securities	147		194
Other, net	Other, net	(17)		(1)		Other, net	(1)		(6)
Net cash used in investing activities	Net cash used in investing activities	(2,202)		(2,580)		Net cash used in investing activities	(952)		(1,035)

Financing activities	Financing activities					Financing activities
Proceeds from short-term borrowings, net		1,161		815
Proceeds from (repayments of) short-term borrowings, net						Proceeds from (repayments of) short-term borrowings, net	(9)		893
Proceeds from issuances of long-term debt	Proceeds from issuances of long-term debt	1,821		2,447		Proceeds from issuances of long-term debt	—		1,821
Repayments of long-term debt, including reacquisition premiums	Repayments of long-term debt, including reacquisition premiums	(399)		0		Repayments of long-term debt, including reacquisition premiums	—		(400)

Dividends paid	Dividends paid	(460)		(421)		Dividends paid	(240)		(223)
Other, net	Other, net	(1)		(23)		Other, net	(15)		(10)
Net cash provided by financing activities		2,122		2,818
Net cash (used in) provided by financing activities						Net cash (used in) provided by financing activities	(264)		2,081

Net change in cash, cash equivalents and restricted cash	Net change in cash, cash equivalents and restricted cash	409		1,386		Net change in cash, cash equivalents and restricted cash	(76)		910
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 ~~(a)~~	Cash, cash equivalents and restricted cash at end of period ~~(a)~~	$	538	$	1,634	Cash, cash equivalents and restricted cash at end of period ~~(a)~~	$	90	$	1,039

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)	$	(390)	$	(364)	Cash paid for interest (net of amounts capitalized)	$	(202)	$	(206)
Cash paid for income taxes, net	Cash paid for income taxes, net	(5)		(10)		Cash paid for income taxes, net	—		(3)

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	$	509	$	436	Accrued property, plant and equipment additions	$	288	$	412
Inventory transfers to property, plant and equipment	Inventory transfers to property, plant and equipment	43		194		Inventory transfers to property, plant and equipment	20		22
Operating lease right-of-use assets		1		8

Allowance for equity funds used during construction	Allowance for equity funds used during construction	32		61		Allowance for equity funds used during construction	13		14
Issuance of common stock for equity awards		35		35
Issuance of common stock for reinvested dividends and/or equity awards						Issuance of common stock for reinvested dividends and/or equity awards	11		19

(a) As of June 30, 2020, $9 million of cash was recorded in Prepayments and other current assets related to MEC.

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)~~

June 30, 2021 Dec. 31, 2020
Assets
Current assets
Cash and cash equivalents $ 538 $ 129
Accounts receivable, net 948 916
Accrued unbilled revenues 699 714
Inventories 500 535
Regulatory assets 1,041 640
Derivative instruments 148 49
Prepaid taxes 52 42
Prepayments and other 221 250
Total current assets 4,147 3,275
Property, plant and equipment, net 44,141 42,950
Other assets
Nuclear decommissioning fund and other investments 3,389 3,096
Regulatory assets 3,225 2,737
Derivative instruments 92 30
Operating lease right-of-use assets 1,390 1,490
Other 395 379
Total other assets 8,491 7,732
Total assets $ 56,779 $ 53,957
Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 21 $ 421
Short-term debt 1,745 584
Accounts payable 1,273 1,237
Regulatory liabilities 336 311
Taxes accrued 428 578
Accrued interest 207 203
Dividends payable 246 231
Derivative instruments 65 53
Operating lease liabilities 220 214
Other 409 407
Total current liabilities 4,950 4,239
Deferred credits and other liabilities
Deferred income taxes 4,807 4,746
Regulatory liabilities 5,387 5,302
Asset retirement obligations 3,059 2,884
Derivative instruments 147 131
Customer advances 196 197
Pension and employee benefit obligations 521 666
Operating lease liabilities 1,236 1,344
Other 208 228
Total deferred credits and other liabilities 15,561 15,498
Commitments and contingencies 0 0
Capitalization
Long-term debt 21,476 19,645
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 538,305,927 and 537,438,394 shares outstanding at June 30, 2021 and Dec. 31, 2020, respectively 1,346 1,344
Additional paid in capital 7,435 7,404
Retained earnings 6,146 5,968
Accumulated other comprehensive loss (135) (141)
Total common stockholders’ equity 14,792 14,575
Total liabilities and equity $ 56,779 $ 53,957
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 June 30, 2021 and 2020
Balance at March 31, 2020		525,033,594	$	1,313	$	6,659	$	5,478	$	(148)		$	13,302
Net income							287					287
Other comprehensive income									3			3
Dividends declared on common stock ($0.43 per share)							(226)					(226)
Issuances of common stock		171,384	0		11							11
Share-based compensation					9		(1)					8
Balance at June 30, 2020		525,204,978	$	1,313	$	6,679	$	5,538	$	(145)		$	13,385

Balance at March 31, 2021		538,076,662	$	1,345	$	7,411	$	6,082	$	(138)		$	14,700
Three Months Ended March 31, 2022 and 2021														Three Months Ended March 31, 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						311					311		Net income							362				362
Other comprehensive income	Other comprehensive income								3			3		Other comprehensive income									3		3
Dividends declared on common stock ($0.4575 per share)	Dividends declared on common stock ($0.4575 per share)						(246)					(246)		Dividends declared on common stock ($0.4575 per share)							(246)				(246)
Issuances of common stock	Issuances of common stock	229,265	1		14							15		Issuances of common stock	638,268		1		14						15

Share-based compensation	Share-based compensation				10		(1)					9		Share-based compensation					(7)		(2)				(9)
Balance at June 30, 2021		538,305,927	$	1,346	$	7,435	$	6,146	$	(135)		$	14,792
Balance at March 31, 2021														Balance at March 31, 2021	538,076,662		$	1,345	$	7,411	$	6,082	$	(138)	$	14,700

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							380				380
Other comprehensive income														Other comprehensive income									7		7
Dividends declared on common stock ($0.4875 per share)														Dividends declared on common stock ($0.4875 per share)							(265)				(265)
Issuances of common stock														Issuances of common stock	505,718		1		11						12

Share-based compensation														Share-based compensation					(13)		(1)				(14)
Balance at March 31, 2022														Balance at March 31, 2022	544,530,987		$	1,361	$	7,801	$	6,686	$	(116)	$	15,732

		Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss			Total Common Stockholders' Equity
		Shares	Par Value		Additional Paid In Capital
Six Months Ended June 30, 2021 and 2020
Balance at Dec. 31, 2019		524,539,000	$	1,311	$	6,656	$	5,413	$	(141)		$	13,239
Net income							582					582
Other comprehensive loss									(4)			(4)
Dividends declared on common stock ($0.86 per share)							(453)					(453)
Issuances of common stock		665,978	2		21							23
Share-based compensation					2		(2)					0
Adoption of ASC Topic 326							(2)					(2)
Balance at June 30, 2020		525,204,978	$	1,313	$	6,679	$	5,538	$	(145)		$	13,385

Balance at Dec. 31, 2020		537,438,394	$	1,344	$	7,404	$	5,968	$	(141)		$	14,575
Net income							673					673
Other comprehensive income									6			6
Dividends declared on common stock ($0.915 per share)							(492)					(492)
Issuances of common stock		867,533	2		28							30

Share-based compensation					3		(3)					0
Balance at June 30, 2021		538,305,927	$	1,346	$	7,435	$	6,146	$	(135)		$	14,792

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

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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


	March 31, 2022		Dec. 31, 2021
Assets
Current assets
Cash and cash equivalents	$	90	$	166
Accounts receivable, net	1,190		1,018
Accrued unbilled revenues	716		862
Inventories	505		631
Regulatory assets	1,049		1,106
Derivative instruments	125		123
Prepaid taxes	40		44
Prepayments and other	307		289
Total current assets	4,022		4,239

Property, plant and equipment, net	45,837		45,457

Other assets
Nuclear decommissioning fund and other investments	3,492		3,628
Regulatory assets	2,841		2,738
Derivative instruments	94		67
Operating lease right-of-use assets	1,239		1,291
Other	460		431
Total other assets	8,126		8,155
Total assets	$	57,985	$	57,851

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	851	$	601
Short-term debt	996		1,005
Accounts payable	1,257		1,409
Regulatory liabilities	359		271
Taxes accrued	685		569
Accrued interest	209		209
Dividends payable	265		249
Derivative instruments	97		69
Operating lease liabilities	203		205
Other	430		459
Total current liabilities	5,352		5,046

Deferred credits and other liabilities
Deferred income taxes	4,822		4,894
Deferred investment tax credits	52		53
Regulatory liabilities	5,470		5,405
Asset retirement obligations	3,210		3,151
Derivative instruments	107		105
Customer advances	192		196
Pension and employee benefit obligations	262		306
Operating lease liabilities	1,094		1,146
Other	158		158
Total deferred credits and other liabilities	15,367		15,414

Commitments and contingencies	0		0
Capitalization
Long-term debt	21,534		21,779
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 544,530,987 and 544,025,269 shares outstanding at March 31, 2022 and Dec. 31, 2021, respectively	1,361		1,360
Additional paid in capital	7,801		7,803
Retained earnings	6,686		6,572
Accumulated other comprehensive loss	(116)		(123)
Total common stockholders’ equity	15,732		15,612
Total liabilities and equity	$	57,985	$	57,851

See Notes to Consolidated Financial Statements

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of ~~June 30, 2021~~March 31, 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 six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020,~~2021; and ~~its~~Xcel Energy’s cash flows for the ~~six~~three months ended ~~June 30, 2021~~March 31, 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 ~~June 30, 2021,~~March 31, 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.


2. Accounting Pronouncements

~~Credit Losses~~— ~~In 2016,~~As of March 31, 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)	June 30, 2021		Dec. 31, 2020		(Millions of Dollars)	March 31, 2022		Dec. 31, 2021
Accounts receivable, net	Accounts receivable, net					Accounts receivable, net
Accounts receivable	Accounts receivable	$	1,039	$	995	Accounts receivable	$	1,303	$	1,124
Less allowance for bad debts	Less allowance for bad debts	(91)		(79)		Less allowance for bad debts	(113)		(106)
Accounts receivable, net	Accounts receivable, net	$	948	$	916	Accounts receivable, net	$	1,190	$	1,018


(Millions of Dollars)	(Millions of Dollars)	June 30, 2021		Dec. 31, 2020		(Millions of Dollars)	March 31, 2022		Dec. 31, 2021
Inventories	Inventories					Inventories
Materials and supplies	Materials and supplies	$	281	$	275	Materials and supplies	$	299	$	289
Fuel	Fuel	166		176		Fuel	147		182
Natural gas	Natural gas	53		84		Natural gas	59		160
Total inventories	Total inventories	$	500	$	535	Total inventories	$	505	$	631


(Millions of Dollars)	(Millions of Dollars)	June 30, 2021		Dec. 31, 2020		(Millions of Dollars)	March 31, 2022		Dec. 31, 2021
Property, plant and equipment, net	Property, plant and equipment, net					Property, plant and equipment, net
Electric plant	Electric plant	$	48,861	$	47,104	Electric plant	$	49,495	$	48,680
Natural gas plant	Natural gas plant	7,315		7,135		Natural gas plant	7,881		7,758
Common and other property	Common and other property	2,524		2,503		Common and other property	2,715		2,602
Plant to be retired (a)	Plant to be retired (a)	630		677		Plant to be retired (a)	1,151		1,200
Construction work in progress	Construction work in progress	1,851		1,877		Construction work in progress	1,733		1,969
Total property, plant and equipment	Total property, plant and equipment	61,181		59,296		Total property, plant and equipment	62,975		62,209
Less accumulated depreciation	Less accumulated depreciation	(17,382)		(16,657)		Less accumulated depreciation	(17,420)		(17,060)
Nuclear fuel	Nuclear fuel	3,057		2,970		Nuclear fuel	3,085		3,081
Less accumulated amortization	Less accumulated amortization	(2,715)		(2,659)		Less accumulated amortization	(2,803)		(2,773)
Property, plant and equipment, net	Property, plant and equipment, net	$	44,141	$	42,950	Property, plant and equipment, net	$	45,837	$	45,457

(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo and Sherco Units 1, 2 and 23 and A.S. King for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.


4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Commercial paper and term loan borrowings outstanding for Xcel Energy:


(Amounts in Millions, Except Interest Rates)	(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2021			Year Ended Dec. 31, 2020			(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2022			Year Ended Dec. 31, 2021
Borrowing limit	Borrowing limit	$	4,300		$	3,100		Borrowing limit	$	3,100		$	3,100
Amount outstanding at period end	Amount outstanding at period end	1,745			584			Amount outstanding at period end	996			1,005
Average amount outstanding	Average amount outstanding	1,521			1,126			Average amount outstanding	1,061			1,399
Maximum amount outstanding	Maximum amount outstanding	1,745			2,080			Maximum amount outstanding	1,357			2,054
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	0.66		%	1.45		%	Weighted average interest rate, computed on a daily basis	0.42		%	0.57		%
Weighted average interest rate at period end	Weighted average interest rate at period end	0.58			0.23			Weighted average interest rate at period end	0.93			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. ~~At both June 30, 2021~~There were $39 million and ~~Dec. 31, 2020, there were $20~~$19 million of letters of credit outstanding under the ~~credit facilities.~~credit facilities at March 31, 2022 and Dec. 31, 2021, respectively. Amounts approximate their fair value and are subject to fees.

~~Table of Contents~~

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.

As of ~~June 30, 2021,~~March 31, 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	$	545	$	705	Xcel Energy Inc.	$	1,250	$	780	$	470
PSCo	PSCo	700		8		692		PSCo	700		31		669
NSP-Minnesota	NSP-Minnesota	500		9		491		NSP-Minnesota	500		11		489
SPS	SPS	500		2		498		SPS	500		214		286
NSP-Wisconsin	NSP-Wisconsin	150		0		150		NSP-Wisconsin	150		—		150
Total	Total	$	3,100	$	564	$	2,536	Total	$	3,100	$	1,036	$	2,064

(a)Expires in June 2024.

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

Table of Contents

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available credit facilities capacity. Xcel Energy Inc. and its utility subsidiaries had 0no direct advances on the credit facilities outstanding as of ~~June 30, 2021~~March 31, 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 June 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 $ 0
2021.

Bilateral Credit Agreement

In April ~~2021, the~~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 ~~June 30, 2021,~~March 31, 2022, NSP-Minnesota’s outstanding letters of credit under the bilateral credit agreement were as follows:

(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75 $ 75 $ 0

~~Long-Term Borrowings and Other Financing Instruments~~

~~During the six months ended June 30, 2021, Xcel Energy Inc. and its utility subsidiaries issued the following:~~

•~~PSCoissued $750 million of 1.875% first mortgage bonds due June 15, 2031.~~

•~~SPS issued $250 million of 3.15% first mortgage bonds due 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 1, 2052.~~


(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	$	75	$	45	$	30

Other Equity — Xcel Energy Inc. issued ~~$28~~$10 million and ~~$20~~$13 million of equity through the DRIP during the ~~six~~three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common ~~stock through a non-cash transaction.~~stock.


5. Revenues

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

Three Months Ended June 30, 2021
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 756 $ 257 $ 11 $ 1,024
C&I 1,282 126 6 1,414
Other 32 0 2 34
Total retail 2,070 383 19 2,472
Wholesale 234 0 0 234
Transmission 148 0 0 148
Other 20 42 0 62
Total revenue from contracts with customers 2,472 425 19 2,916
Alternative revenue and other 125 24 3 152
Total revenues $ 2,597 $ 449 $ 22 $ 3,068

Three Months Ended June 30, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 718 $ 167 $ 10 $ 895
C&I 1,075 73 6 1,154
Other 31 0 1 32
Total retail 1,824 240 17 2,081
Wholesale 160 0 0 160
Transmission 153 0 0 153
Other 21 26 0 47
Total revenue from contracts with customers 2,158 266 17 2,441
Alternative revenue and other 128 14 3 145
Total revenues $ 2,286 $ 280 $ 20 $ 2,586


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

~~Table of Contents~~

Six Months Ended June 30, 2021
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,489 $ 642 $ 21 $ 2,152
C&I 2,315 312 15 2,642
Other 62 0 3 65
Total retail 3,866 954 39 4,859
Wholesale 977 0 0 977
Transmission 294 0 0 294
Other 34 61 0 95
Total revenue from contracts with customers 5,171 1,015 39 6,225
Alternative revenue and other 296 81 7 384
Total revenues $ 5,467 $ 1,096 $ 46 $ 6,609


		Six Months Ended June 30, 2020									Three Months Ended March 31, 2021
(Millions of Dollars)	(Millions of Dollars)	Electric		Natural Gas		All Other		Total		(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types	Major revenue types									Major revenue types
Revenue from contracts with customers:	Revenue from contracts with customers:									Revenue from contracts with customers:
Residential	Residential	$	1,394	$	522	$	21	$	1,937	Residential	$	733	$	384	$	10	$	1,127
C&I	C&I	2,141		253		15		2,409		C&I	1,033		187		9		1,229
Other	Other	60		0		2		62		Other	30		—		2		32
Total retail	Total retail	3,595		775		38		4,408		Total retail	1,796		571		21		2,388
Wholesale	Wholesale	326		0		0		326		Wholesale	743		—		—		743
Transmission	Transmission	285		0		0		285		Transmission	146		—		—		146
Other	Other	38		58		0		96		Other	13		19		—		32
Total revenue from contracts with customers	Total revenue from contracts with customers	4,244		833		38		5,115		Total revenue from contracts with customers	2,698		590		21		3,309
Alternative revenue and other	Alternative revenue and other	245		30		7		282		Alternative revenue and other	172		57		3		232
Total revenues	Total revenues	$	4,489	$	863	$	45	$	5,397	Total revenues	$	2,870	$	647	$	24	$	3,541


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~~2021 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 between the statutory rate and ETR:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended March 31
		2021		2020		2021		2020			2022		2021
Federal statutory rate	Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	Federal statutory rate	21.0	%	21.0	%
State tax (net of federal tax effect)	State tax (net of federal tax effect)	4.9		5.1		4.9		5.0		State tax (net of federal tax effect)	4.9		4.9
Decreases:	Decreases:									Decreases:
Wind PTCs	Wind PTCs	(33.1)		(21.1)		(28.4)		(19.1)		Wind PTCs	(34.4)		(24.6)
Plant regulatory differences (a)	Plant regulatory differences (a)	(6.6)		(7.1)		(6.3)		(7.8)		Plant regulatory differences (a)	(4.8)		(6.1)
Other tax credits, net operating loss & tax credits allowances										Other tax credits, net operating loss & tax credits allowances	(1.5)		(1.1)
Other (net)	Other (net)	(0.1)		(2.6)		(1.0)		(2.5)		Other (net)	(0.4)		(0.6)
Effective income tax rate	Effective income tax rate	(13.9)	%	(4.7)	%	(9.8)	%	(3.4)	%	Effective income tax rate	(15.2)	%	(6.5)	%

(a)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 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~~						~~January 2022~~
~~2017~~						~~September 2021~~

Additionally, 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 June 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~~						~~2009~~
~~Minnesota~~						~~2013~~
~~Texas~~						~~2012~~
~~Wisconsin~~						~~2016~~

•In July 2020, Minnesota began a review of tax years 2015 - 2018. In February 2021, Minnesota concluded its review and commenced an audit of the same tax years. NaN 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 June 30, 2021.~~

~~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) June 30, 2021 Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions $ 43 $ 41��
Unrecognized tax benefit — Temporary tax positions 11 11
Total unrecognized tax benefit $ 54 $ 52

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

(Millions of Dollars) June 30, 2021 Dec. 31, 2020
NOL and tax credit carryforwards $ (33) $ (31)

~~As IRS audits resume and the state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $28 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.~~

~~Table of Contents~~

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

(Millions of Dollars) June 30, 2021 Dec. 31, 2020
Payable for interest related to unrecognized tax benefits at beginning of period $ (3) $ 0
Interest expense related to unrecognized tax benefits 0 (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 June 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.

Table of Contents

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

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

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

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

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


		Three Months Ended June 30		Six Months Ended June 30			Three Months Ended March 31
(Shares in Millions)	(Shares in Millions)	2021	2020	2021	2020	(Shares in Millions)	2022	2021
Basic	Basic	539	527	539	526	Basic	545	538
Diluted (a)	Diluted (a)	539	527	539	527	Diluted (a)	545	539

(a)Diluted common shares outstanding included common stock equivalents of ~~0.3 million and 0.5~~ 0.2 million for the three months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020, respectively. Diluted common shares outstanding included common stock equivalents of 0.3 million and 0.7 million for the six months ended June 30, 2021 and 2020,~~ respectively.


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

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

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

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When 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 a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.

~~Table of Contents~~

The value of an FTR is derived from, and designed to offset, the cost 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.

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 the limited observability 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 through fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction and therefore changes in the fair value of the yet to be settled portions of most FTRs are 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.

Table of Contents

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 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 billion and ~~$981 million~~$1.3 billion as of ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, respectively, and unrealized losses were $3$37 million and $5$7 million as of ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, respectively.

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


		June 30, 2021													March 31, 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	$	30	$	30	$	0	$	0	$	0	$	30	Cash equivalents	$	80	$	80	$	—	$	—	$	—	$	80
Commingled funds	Commingled funds	800		0		0		0		1,164		1,164		Commingled funds	871		—		—		—		1,258		1,258
Debt securities	Debt securities	612		0		641		16		0		657		Debt securities	626		—		606		10		—		616
Equity securities	Equity securities	408		1,185		2		0		0		1,187		Equity securities	409		1,159		1		—		—		1,160
Total	Total	$	1,850	$	1,215	$	643	$	16	$	1,164	$	3,038	Total	$	1,986	$	1,239	$	607	$	10	$	1,258	$	3,114

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes ~~$189~~$215 million of equity method investments and ~~$162~~$163 million of rabbi trust assets and miscellaneous investments.


		Dec. 31, 2020													Dec. 31, 2021
				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	$	40	$	40	$	0	$	0	$	0	$	40	Cash equivalents	$	64	$	64	$	—	$	—	$	—	$	64
Commingled funds	Commingled funds	787		0		0		0		1,041		1,041		Commingled funds	856		—		—		—		1,294		1,294
Debt securities	Debt securities	528		0		572		13		0		585		Debt securities	631		—		666		9		—		675
Equity securities	Equity securities	446		1,109		2		0		0		1,111		Equity securities	411		1,222		1		—		—		1,223
Total	Total	$	1,801	$	1,149	$	574	$	13	$	1,041	$	2,777	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 six~~ months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of ~~June 30, 2021:~~March 31, 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	$	210	$	292	$	657	Debt securities	$	2	$	142	$	193	$	279	$	616

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:


		June 30, 2021											March 31, 2022
				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	$	23	$	23	$	0	$	0	$	23	Cash equivalents	$	20	$	20	$	—	$	—	$	20
Mutual funds	Mutual funds	71		84		0		0		84		Mutual funds	75		85		—		—		85
Total	Total	$	94	$	107	$	0	$	0	$	107	Total	$	95	$	105	$	—	$	—	$	105


		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	$	0	$	0	$	32	Cash equivalents	$	20	$	20	$	—	$	—	$	20
Mutual funds	Mutual funds	60		70		0		0		70		Mutual funds	75		89		—		—		89
Total	Total	$	92	$	102	$	0	$	0	$	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.

~~Table of Contents~~

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 ~~June 30, 2021,~~March 31, 2022, accumulated other comprehensive loss related to ~~settled~~ interest rate derivatives included $6$5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of ~~June 30, 2021,~~March 31, 2022, Xcel Energy had 0 unsettled interest swaps outstanding with a notional amount of $245 million. These interest rate ~~derivatives.~~derivatives were designated as cash flow hedges, and as such, changes in fair value are recorded to other comprehensive income.

Table of Contents

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 ~~June 30, 2021,~~March 31, 2022, Xcel Energy had 0no commodity contracts designated as cash flow hedges.

Xcel Energy 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)

June 30, 2021

Dec. 31, 2020

(Amounts in Millions) (a)(b)

March 31, 2022

Dec. 31, 2021

Megawatt hours of electricity

122

Megawatt hours of electricity

Million British thermal units of natural gas

169

175

Million British thermal units of natural gas

141

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.

As of ~~June 30, 2021, 6~~March 31, 2022, 4 of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$118~~$80 million, or ~~44%~~31%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. NaN of the 10 most significant counterparties, comprising ~~$27~~$56 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 of these significant counterparties, comprising ~~$62~~$59 million or 23% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

I~~mpact~~

Impact of Derivative Activity —

Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities
Three Months Ended June 30, 2021
Other derivative instruments
Electric commodity $ 0 $ 11
Natural gas commodity 0 (1)
Total $ 0 $ 10
Six Months Ended June 30, 2021
Other derivative instruments
Electric commodity $ 0 $ 13
Total $ 0 $ 13
Three Months Ended June 30, 2020
Other derivative instruments
Natural gas commodity $ 0 $ (3)
Total $ 0 $ (3)
Six Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate $ (13) $ 0
Total $ (13) $ 0
Other derivative instruments
Natural gas commodity $ 0 $ (3)
Total $ 0 $ (3)


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
Three Months Ended March 31, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	6	$	—
Total	$	6	$	—
Other derivative instruments:
Electric commodity	$	—	$	1
Natural gas commodity	—		4
Total	$	—	$	5











Three Months Ended March 31, 2021



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

~~Table of Contents~~


		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 June 30, 2021
Derivatives designated as cash flow hedges
Three Months Ended March 31, 2022											Three Months Ended March 31, 2022
Derivatives designated as cash flow hedges:											Derivatives designated as cash flow hedges:
Interest rate	Interest rate	$	2	(a)	$	0		$	0		Interest rate		$	2	(a)	$	—		$	—
Total	Total	$	2		$	0		$	0		Total		$	2		$	—		$	—
Other derivative instruments
Commodity trading		$	0		$	0		$	12	(b)
Electric commodity		0			3		(c)	0

Total		$	0		$	3		$	12

Six Months Ended June 30, 2021
Derivatives designated as cash flow hedges
Interest rate		$	6	(a)	$	0		$	0
Total		$	6		$	0		$	0
Other derivative instruments
Other derivative instruments:											Other derivative instruments:
Commodity trading	Commodity trading	$	0		$	0		$	48	(b)	Commodity trading		$	—		$	—		$	2	(b)
Electric commodity	Electric commodity	0			(23)		(c)	0			Electric commodity		—			(13)		(c)	—
Natural gas commodity	Natural gas commodity	0			8		(d)	(10)		(d)	Natural gas commodity		—			3		(d)	(17)		(d)(e)
Total	Total	$	0		$	(15)		$	38		Total		$	—		$	(10)		$	(15)

Three Months Ended June 30, 2020
Derivatives designated as cash flow hedges

Three Months Ended March 31, 2021											Three Months Ended March 31, 2021
Derivatives designated as cash flow hedges:											Derivatives designated as cash flow hedges:
Interest rate	Interest rate	$	2	(a)	$	0		$	0		Interest rate		$	2	(a)	$	—		$	—
Total	Total	$	2		$	0		$	0		Total		$	2		$	—		$	—
Other derivative instruments
Commodity trading		$	0		$	0		$	(3)	(b)
Electric commodity		0			(3)		(c)	0
Total		$	0		$	(3)		$	(3)

Six Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate		$	4	(a)	$	0		$	0
Total		$	4		$	0		$	0
Other derivative instruments
Other derivative instruments:											Other derivative instruments:
Commodity trading	Commodity trading	$	0		$	0		$	(5)	(b)	Commodity trading		$	—		$	—		$	32	(b)
Electric commodity	Electric commodity	0			(7)		(c)	0			Electric commodity		—			3		(c)	—
Natural gas commodity	Natural gas commodity	0			5		(d)	(6)		(d)	Natural gas commodity		—			8		(d)	(10)		(d)(e)
Total	Total	$	0		$	(2)		$	(11)		Total		$	—		$	11		$	22

(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.

(d)~~Amounts for both the six months ended June 30, 2021 and 2020 included 0 settlement gains or~~Settlement 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 six months ended June 30, 2021 and 2020 relaterelated to natural gas operations ~~and were~~are recorded 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 0no derivative instruments designated as fair value hedges during the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020.~~2021.

Table of Contents

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 ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, there were $6$4 million and $4$3 million, respectively, of derivative liabilities with such underlying contract ~~provisions, respectively.~~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 ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, there were approximately ~~$69~~$94 million and ~~$60~~$64 million, respectively, of derivative liabilities with such underlying contract ~~provisions, respectively.~~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 0no collateral posted related to adequate assurance clauses in derivative contracts as of ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020~~2021.

~~Table of Contents~~

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


		June 30, 2021													Dec. 31, 2020																					March 31, 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:																								Derivatives designated as cash flow hedges:
Interest rate																								Interest rate				$	—				$	6				$	—				$	6			$	—			$	6			$	—			$	—			$	—			$	—			$	—			$	—
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	17	$	178	$	11	$	206	$	(168)		$	38	$	2	$	67	$	1	$	70			$	(52)				$	18	Commodity trading				$	56				$	188			$	64				$	308			$	(231)			$	77			$	22			$	137			$	21			$	180			$	(134)		$	46
Electric commodity	Electric commodity	0		0		98		98		(1)			97		0		0		20		20				(1)					19		Electric commodity				—					—				38				38				(1)				37				—				—				57				57				(1)			56
Natural gas commodity	Natural gas commodity	0		10		0		10		0			10		0		9		0		9				0					9		Natural gas commodity				—					—				—				—				—				—				—				18				—				18				—			18
Total current derivative assets	Total current derivative assets	$	17	$	188	$	109	$	314	$	(169)		145		$	2	$	76	$	21	$	99			$	(53)				46		Total current derivative assets				$	56				$	194			$	102			$	352			$	(232)			120				$	22			$	155			$	78			$	255			$	(135)		120
PPAs (b)	PPAs (b)												3																	3		PPAs (b)																									5																							3
Current derivative instruments	Current derivative instruments												$	148																$	49	Current derivative instruments																									$	125																						$	123
Noncurrent derivative assets	Noncurrent derivative assets																															Noncurrent derivative assets
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	10	$	117	$	82	$	209	$	(125)		$	84	$	8	$	66	$	8	$	82			$	(62)				$	20	Commodity trading				$	36				$	66			$	117			$	219			$	(135)			$	84			$	16			$	63			$	89			$	168			$	(107)		$	61

Electric commodity																								Electric commodity				—					—					5					5				—				5				—				—				—				—				—				—
Total noncurrent derivative assets	Total noncurrent derivative assets	$	10	$	117	$	82	$	209	$	(125)		84		$	8	$	66	$	8	$	82			$	(62)				20		Total noncurrent derivative assets				$	36				$	66			$	122			$	224			$	(135)			89				$	16			$	63			$	89			$	168			$	(107)		61
PPAs (b)	PPAs (b)												8																	10		PPAs (b)																									5																							6
Noncurrent derivative instruments	Noncurrent derivative instruments												$	92																$	30	Noncurrent derivative instruments																									$	94																						$	67


		June 30, 2021													Dec. 31, 2020																March 31, 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	$	20	$	188	$	12	$	220	$	(175)		$	45	$	4	$	64	$	17	$	85		$	(58)		$	27	Commodity trading		$	47			$	213	$	50		$	310			$	(230)		$	80			$	19			$	148		$	20		$	187		$	(143)		$	44
Electric commodity	Electric commodity	0		0		1		1		(1)			0		0		0		1		1			(1)			0		Electric commodity		—				—		1		1				(1)			—				—				—			1			1			(1)			—
Natural gas commodity	Natural gas commodity	0		3		0		3		0			3		0		9		0		9			0			9		Natural gas commodity		—				—		—		—				—			—				—				8			—			8			—			8
Total current derivative liabilities	Total current derivative liabilities	$	20	$	191	$	13	$	224	$	(176)		48		$	4	$	73	$	18	$	95		$	(59)		36		Total current derivative liabilities		$	47			$	213	$	51	$	311			$	(231)		80				$	19			$	156		$	21		$	196		$	(144)		52
PPAs (b)	PPAs (b)												17														17		PPAs (b)																	17																				17
Current derivative instruments	Current derivative instruments												$	65													$	53	Current derivative instruments																	$	97																			$	69
Noncurrent derivative liabilities	Noncurrent derivative liabilities																												Noncurrent derivative liabilities
Other derivative instruments:	Other derivative instruments:																								Other derivative instruments:
Commodity trading	Commodity trading	$	7	$	116	$	107	$	230	$	(132)		$	98	$	3	$	58	$	60	$	121		$	(47)		$	74	Commodity trading		$	40			$	64	$	133	$	237			$	(168)		$	69			$	18			$	48		$	127		$	193		$	(128)		$	65
Total noncurrent derivative liabilities	Total noncurrent derivative liabilities	$	7	$	116	$	107	$	230	$	(132)		98		$	3	$	58	$	60	$	121		$	(47)		74		Total noncurrent derivative liabilities		$	40			$	64	$	133	$	237			$	(168)		69				$	18			$	48		$	127		$	193		$	(128)		65
PPAs (b)	PPAs (b)												49														57		PPAs (b)																	38																				40
Noncurrent derivative instruments	Noncurrent derivative instruments												$	147													$	131	Noncurrent derivative instruments																	$	107																			$	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 ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020.~~2021. At both ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, derivative assets and liabilities include ~~$15 million of~~no obligations to return cash collateral. At ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, derivative assets and liabilities include rights to reclaim cash collateral of ~~$29~~$34 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)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.

1614

Table of Contents

Changes in Level 3 commodity derivatives:


		Three Months Ended June 30
(Millions of Dollars)		2021		2020
Balance at April 1		$	(13)	$	4
Purchases		63		37
Settlements		(32)		(25)
Net transactions recorded during the period:
Gains recognized in earnings (a)		9		9
Net gains recognized as regulatory assets and liabilities		44		9
Balance at June 30		$	71	$	34

		Six Months Ended June 30					Three Months Ended March 31
(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	Purchases	63		49		Purchases	5		—
Settlements	Settlements	(48)		(42)		Settlements	(50)		(16)
Net transactions recorded during the period:	Net transactions recorded during the period:					Net transactions recorded during the period:
Gains recognized in earnings (a)	Gains recognized in earnings (a)	47		14		Gains recognized in earnings (a)	42		38
Net gains recognized as regulatory assets and liabilities		58		9
Balance at June 30		$	71	$	34
Net (losses) gains recognized as regulatory assets and liabilities						Net (losses) gains recognized as regulatory assets and liabilities	24		14
Balance at March 31						Balance at March 31	$	40	$	(13)

(a)~~Presented amounts relate~~Level 3 net gains recognized in earnings are subject to offsetting net losses of derivative instruments ~~held at the end of the period. The consolidated income statement also includes gains and losses on Level~~categorized as levels 1 and 2 ~~instruments, and Level 3 instruments settled during~~in the ~~period.~~income statement.

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were 0no transfers of amounts between levels for derivative instruments for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 and ~~2020.~~2021.

Fair Value of Long-Term Debt

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


		June 30, 2021				Dec. 31, 2020					March 31, 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	$	21,497	$	24,686	$	20,066	$	24,412	Long-term debt, including current portion	$	22,385	$	22,807	$	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 ~~June 30, 2021~~March 31, 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 June 30									Three Months Ended March 31
		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	$	1	$	0	Service cost	$	24	$	26	$	—	$	—
Interest cost (a)	Interest cost (a)	26		31		3		5		Interest cost (a)	27		26		4		4
Expected return on plan assets (a)	Expected return on plan assets (a)	(51)		(52)		(5)		(5)		Expected return on plan assets (a)	(52)		(52)		(4)		(4)
Amortization of prior service credit (a)	Amortization of prior service credit (a)	(1)		(1)		(2)		(2)		Amortization of prior service credit (a)	—		—		(2)		(2)
Amortization of net loss (a)	Amortization of net loss (a)	27		25		2		1		Amortization of net loss (a)	19		27		1		1
Settlement charge (b)										Settlement charge (b)	(1)		—		—		—
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	27		27		(1)		(1)		Net periodic benefit cost (credit)	17		27		(1)		(1)
Effects of regulation	Effects of regulation	0		1		0		1		Effects of regulation	5		(1)		1		1
Net benefit cost (credit) recognized for financial reporting	Net benefit cost (credit) recognized for financial reporting	$	27	$	28	$	(1)	$	0	Net benefit cost (credit) recognized for financial reporting	$	22	$	26	$	—	$	—

Six Months Ended June 30
2021 2020 2021 2020
(Millions of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 52 $ 45 $ 1 $ 1
Interest cost (a)
52 68 7 9
Expected return on plan assets (a)
(103) (103) (9) (10)
Amortization of prior service credit (a)
(1) (2) (4) (4)
Amortization of net loss (a)
54 47 3 2
Net periodic benefit cost (credit) 54 55 (2) (2)
Effects of regulation (1) 2 1 1
Net benefit cost (credit) recognized for financial reporting $ 53 $ 57 $ (1) $ (1)

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

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

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


10. Commitments and Contingencies

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

Legal

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

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

~~Table of Contents~~

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 ~~cases remain~~case remains active which ~~include an MDL~~includes a multi-district litigation matter consisting of ~~a Colorado purported class (Breckenridge) and~~ a Wisconsin purported class (Arandell Corp.).

~~Breckenridge/Colorado~~ — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. Settlement of approximately $3 million was reached in February 2021. The parties have sought and are awaiting court approval of the settlement. A hearing was held on July 22, 2021. A decision is anticipated in Q3.

~~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. 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 seeking an unspecified amount of damages. CORE alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo filed a motion to dismiss several of CORE’s claims. 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.

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.

Table of Contents

Minnesota Winter Storm Uri Costs — In Minnesota, NSP-Minnesota is participating in a contested case regarding the prudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses.

NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders.

NSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event.

In March 2022, following February 2022 ALJ hearings, the Company and intervenors subsequently submitted initial and reply briefs to the ALJ. The OAG modified its position, recommending disallowances of up to $148 million, the largest recommendation among the intervenor positions. An ALJ decision is expected in late May and an MPUC decision is expected in Q3 of 2022.

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. A final decision by the MPUC is pending. A loss related to this matter is deemed remote.

Westmoreland Arbitration — In November 2014, insurers ~~for~~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.Westmoreland’s insurers have recently clarified that they will seek to recover $19 million in damages, plus prejudgment interest. 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. ~~It is uncertain when a~~Parties participated in mediation in the second quarter of 2022. A final ~~resolution will occur, but it is unlikely an arbitration~~ hearing ~~will take place before the fourth quarter 2021.~~has been scheduled for October 2022. 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 for rehearing regarding the new~~has subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to 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 complaint without refunds.~~

~~In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569~~methodology/calculations 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 the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. timing. NSP-Minnesota has recognized a liability for its best estimate of final refunds to ~~customers. Each 10 basis point reduction in ROE~~customers for ~~the first~~applicable 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.~~periods.

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 with initial briefs filed~~Circuit. Oral arguments were held in ~~March~~late 2021 and ~~final briefs~~a decision is expected ~~in August 2021.~~

~~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, following a comment period expected to be complete by the end of ~~2021 or 2022, NSP-Minnesota, NSP-Wisconsin and SPS would prospectively discontinue charging their current 0.5% ROE incentive adders. Amounts related to a discontinuance~~the third quarter of ~~the adder would ultimately be offset by an increase in retail rates, following future rate cases.~~2022.

~~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. In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. ~~SPS has intervened in both~~In August 2021, the D.C. Circuit issued a decision denying these appeals ~~in support of~~and upholding the ~~FERC. Any refunds~~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. ~~This~~In February 2022, FERC issued an order rejecting SPS’ request for hearing. SPS has appealed that order. That appeal ~~is stayed pending the outcome~~has been combined with SPS’ prior appeal.

Table of ~~the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.~~Contents

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) ~~or, absent a move by LP&L to ERCOT, upon LP&L’s election.~~. 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.

~~Gas Cost Adjustment 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. Initial comments were due July 23, 2021, reply comments are due Aug. 6, 2021 and a hearing is scheduled for Aug. 26, 2021. A CPUC decision in expected in the third quarter of 2021.

Environmental

MGP, Landfill and Disposal Sites

Xcel Energy is investigating, remediating or performing post-closure actions at 1314 MGP, landfill or other disposal sites across its service territories.

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 landfills and surface impoundments. Currently, Xcel Energy has 8 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, 0no 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 for corrective action at 2 locations, 1 of which indicates potential offsite impacts to groundwater. The total cost is uncertain, but could be up to $35 million. PSCo is continuing to assess the financial and regulatory impacts.

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

In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined ~~impoundment at a cost of $9 million.~~impoundment. 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~~a 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~~removed the pond from service ~~until~~in June ~~18, 2021.~~ 2021 and did not meet the April 2021 deadline.

PSCo ~~expects to negotiate~~is in the process of negotiating a compliance order with the ~~EPA.~~EPA addressing the closure deadline as well as other issues. PSCo ~~will also now proceed~~is proceeding with ~~closure of~~ the pond ~~with~~closure at an estimated cost of $3 million.

Closure costs for existing impoundments are included in the calculation of the ~~ARO.~~asset retirement obligation.

~~Table~~Federal Clean Water Act Section 316(b) — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of ~~Contents~~aquatic species. Xcel Energy estimates the likely future cost for complying with impingement and entrainment requirements is approximately $39 million, to be incurred between 2022 and 2028. Xcel Energy believes 6 NSP-Minnesota plants and 2 NSP-Wisconsin plants could be required to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $192 million. Xcel Energy anticipates these costs will be fully recoverable through regulatory 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 that would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.

In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether sulfur dioxide emission reductions beyond those required in the BART alternative rule referenced above are needed at Tolk under the “reasonable progress” requirements. As states are now proceeding with the second regional haze planning period, the EPA may choose not to act on the remanded rule, but could impose additional requirements as part of a BART reconsideration or as part of the second planning period.

Leases

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

Components of lease expense:


		Three Months Ended June 30					Three Months Ended March 31
(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	$	43	PPA capacity payments	$	63	$	58
Other operating leases (a)	Other operating leases (a)	9		9		Other operating leases (a)	13		8
Total operating lease expense (b)	Total operating lease expense (b)	$	65	$	52	Total operating lease expense (b)	$	76	$	66
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 $2$1 million for 2022 and ~~$1 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.

Six Months Ended June 30
(Millions of Dollars) 2021 2020
Operating leases
PPA capacity payments $ 114 $ 89
Other operating leases (a)
17 17
Total operating lease expense (b)
$ 131 $ 106
Finance leases
Amortization of ROU assets $ 4 $ 3
Interest expense on lease liability 8 9
Total finance lease expense $ 12 $ 12

~~(a)Includes short-term lease expense~~Table of ~~$3 million and $2 million~~ ~~for 2021 and 2020, respectively.~~ Contents

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

Commitments under operating and finance leases as of ~~June 30, 2021:~~March 31, 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	$	1,532	$	196	$	1,728	$	249	Total minimum obligation	$	1,348	$	178	$	1,526	$	239
Interest component of obligation	Interest component of obligation	(235)		(37)		(272)		(175)		Interest component of obligation	(197)		(32)		(229)		(167)
Present value of minimum obligation	Present value of minimum obligation	$	1,297	159		1,456		74		Present value of minimum obligation	$	1,151	146		1,297		72
Less current portion	Less current portion					(220)		(3)		Less current portion					(203)		(4)
Noncurrent operating and finance lease liabilities	Noncurrent operating and finance lease liabilities					$	1,236	$	71	Noncurrent operating and finance lease liabilities					$	1,094	$	68

(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.~~energy that they purchase. These specific PPAs create a variable interest in the IPP.

The utility subsidiaries had approximately 4,037 MW and 4,062 MW of capacity under long-term PPAs at ~~both June 30, 2021~~March 31, 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 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 ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020,~~2021, Xcel Energy Inc. and its subsidiaries had 0no 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 $61 million and $60 million ~~and $62 million~~ at ~~June 30, 2021~~March 31, 2022 and Dec. 31, ~~2020, respectively.~~2021, respectively.

Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.

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

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11. Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three ~~and six~~ months ended ~~June 30, 2021~~March 31, 2022 and ~~2020:~~2021:

Three Months Ended June 30, 2021 Three Months Ended June 30, 2020
(Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at April 1 $ (82) $ (56) $ (138) $ (88) $ (60) $ (148)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0, $0, $1 and $0, respectively) (a)
2 0 2 1 0 1
Amortization of net actuarial loss (net of taxes of $0, $0, $0 and $1, respectively ) (b)
0 1 1 0 2 2
Net current period other comprehensive income 2 1 3 1 2 3
Accumulated other comprehensive loss at June 30 $ (80) $ (55) $ (135) $ (87) $ (58) $ (145)


	Three Months Ended March 31, 2022						Three Months Ended March 31, 2021
(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	$	(75)	$	(48)	$	(123)	$	(85)	$	(56)	$	(141)
Other comprehensive gain before reclassifications (net of taxes of $1, $—, $— and $—, respectively)	5		—		5		—		—		—
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $—, $1 and $—, respectively) (a)	1		—		1		3		—		3
Amortization of net actuarial loss (net of taxes of $—, $—, $— and $—, respectively) (b)	—		1		1		—		—		—
Net current period other comprehensive income	6		1		7		3		—		3
Accumulated other comprehensive loss at March 31	$	(69)	$	(47)	$	(116)	$	(82)	$	(56)	$	(138)

Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
(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 $ (85) $ (56) $ (141) $ (80) $ (61) $ (141)
Other comprehensive gain (loss) before reclassifications (net of taxes of $0, $0, $(3) and $0, respectively) 0 0 0 (10) 0 (10)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $0, $1 and $0, respectively) (a)
5 0 5 3 0 3
Amortization of net actuarial loss (net of taxes of $0, $1, $0 and $1, respectively) (b)
0 1 1 0 3 3
Net current period other comprehensive income (loss) 5 1 6 (7) 3 (4)
Accumulated other comprehensive loss at June 30 $ (80) $ (55) $ (135) $ (87) $ (58) $ (145)

(a)Included in interest charges.

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

12. Segment Information

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

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

Xcel Energy has the following reportable segments:

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

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

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Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, 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 ~~$189~~$215 million and ~~$165~~$208 million as of ~~June 30, 2021~~March 31, 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.

~~Table of Conten~~t s

Xcel Energy’s segment information:


		Three Months Ended June 30					Three Months Ended March 31
(Millions of Dollars)	(Millions of Dollars)	2021		2020		(Millions of Dollars)	2022		2021
Regulated Electric	Regulated Electric					Regulated Electric
Operating revenues from external customers		$	2,597	$	2,286
Intersegment revenue		1		1

Total revenues	Total revenues	$	2,598	$	2,287	Total revenues	$	2,633	$	2,870
Net income	Net income	304		289		Net income	278		269
Regulated Natural Gas	Regulated Natural Gas					Regulated Natural Gas

Total revenues	Total revenues	$	449	$	280	Total revenues	$	1,090	$	647
Net income	Net income	33		20		Net income	130		118
All Other	All Other					All Other
Total revenues	Total revenues	$	22	$	20	Total revenues	$	28	$	24
Net loss	Net loss	(26)		(22)		Net loss	(28)		(25)
Consolidated Total	Consolidated Total					Consolidated Total
Total revenues	Total revenues	$	3,069	$	2,587	Total revenues	$	3,751	$	3,541
Reconciling eliminations		(1)		(1)
Total operating revenues		$	3,068	$	2,586

Net income	Net income	311		287		Net income	380		362

Six Months Ended June 30
(Millions of Dollars) 2021 2020
Regulated Electric
Operating revenues from external customers $ 5,467 $ 4,489
Intersegment revenue 1 1
Total revenues $ 5,468 $ 4,490
Net income 573 516
Regulated Natural Gas
Operating revenues from external customers $ 1,096 $ 863
Intersegment revenue 1 1
Total revenues 1097 864
Net income $ 151 $ 111
All Other
Total revenues 46 45
Net loss $ (51) $ (45)
Consolidated Total
Total revenues $ 6,611 $ 5,399
Reconciling eliminations (2) (2)
Total operating revenues $ 6,609 $ 5,397
Net income 673 582

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~~subsidiaries.For the three ~~and six~~ months ended ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

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

Summarized diluted EPS for Xcel Energy:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended March 31
Diluted Earnings (Loss) Per Share	Diluted Earnings (Loss) Per Share	2021		2020		2021		2020		Diluted Earnings (Loss) Per Share	2022		2021
PSCo	PSCo	$	0.25	$	0.21	$	0.56	$	0.45	PSCo	$	0.32	$	0.31
NSP-Minnesota	NSP-Minnesota	0.21		0.22		0.45		0.43		NSP-Minnesota	0.23		0.24
SPS	SPS	0.13		0.14		0.23		0.22		SPS	0.10		0.11
NSP-Wisconsin	NSP-Wisconsin	0.03		0.02		0.09		0.09		NSP-Wisconsin	0.09		0.06
Earnings from equity method investments - WYCO		0.01		0.01		0.02		0.02
Earnings from equity method investments — WYCO										Earnings from equity method investments — WYCO	0.01		0.01
Regulated utility (a)	Regulated utility (a)	0.62		0.60		1.35		1.20		Regulated utility (a)	0.75		0.73
Xcel Energy Inc. and Other	Xcel Energy Inc. and Other	(0.04)		(0.07)		(0.10)		(0.10)		Xcel Energy Inc. and Other	(0.05)		(0.06)
Total (a)	Total (a)	$	0.58	$	0.54	$	1.25	$	1.10	Total (a)	$	0.70	$	0.67

(a) Amounts may not add due to rounding.

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Summary of Earnings

Xcel Energy — Xcel Energy’s GAAP first quarter diluted earnings ~~increased $0.04~~were $0.70 per share ~~for the second quarter of 2021 and increased $0.15~~in 2022 compared with $0.67 per share ~~year-to-date. Earnings primarily reflect higher electric and natural gas margins (driven~~in 2021. The increase was driven by regulatory recovery of capital investment, ~~recovery, regulatory outcomes and weather-normalized sales growth as compared to 2020, which was more adversely impacted by COVID-19). These drivers were~~ partially offset by higher depreciation, interest expense and O&M ~~expenses, interest charges~~expenses. Costs for natural gas sold and ~~lower AFUDC.~~transported significantly increased in 2022 primarily due to market price fluctuations. However, fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in revenues are offset by the related variation in costs).

PSCo — Earnings increased ~~$0.04~~$0.01 per share for the ~~second~~first quarter of ~~2021 and $0.11 per share year-to-date. The increase in year-to-date earnings reflects higher natural gas and electric margins (primarily~~2022, reflecting regulatory recovery of capital investment ~~recovery~~ and ~~regulatory outcomes),~~higher demand revenues, partially offset by ~~additional~~increased depreciation, O&M expenses and ~~other taxes (other than income taxes).~~incremental power costs from the Comanche Unit 3 outage.

NSP-Minnesota — Earnings decreased $0.01 per share for the ~~second~~first quarter of ~~2021 and increased $0.02 per share year-to-date. The increase in year-to-date earnings reflects higher electric margin (primarily~~2022, as regulatory recovery of capital investment ~~recovery), partially~~was offset by increased depreciation and O&M expenses.

SPS — Earnings decreased $0.01 per share for the ~~second~~first quarter of ~~2021~~2022, primarily due to taxes (other than income taxes) and ~~increased $0.01 per share year-to-date. The increase in year-to-date earnings reflects higher electric margin (capital investment recovery and regulatory outcomes),~~impacts associated with Winter Storm Uri, partially offset by ~~increased depreciation and O&M expenses.~~favorable sales.

NSP-Wisconsin — Earnings increased ~~$0.01~~$0.03 per share for the ~~second~~first quarter of ~~2021~~2022, reflecting the impact of regulatory rate outcomes and ~~were flat year-to-date.~~higher sales attributable to weather, partially offset by higher 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.

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 June 30 Six Months Ended June 30
GAAP and ongoing diluted EPS — 2020 $ 0.54 $ 1.10
Components of change - 2021 vs. 2020
Higher electric margin 0.14 0.25
Higher natural gas margins 0.05 0.12
Lower ETR (a)
0.06 0.12
Higher other income (expense), net — 0.02
Higher depreciation and amortization (0.08) (0.16)
Higher O&M expenses (0.07) (0.08)
Lower AFUDC (0.05) (0.07)
Higher interest charges (0.01) (0.01)
Other, net — (0.04)
GAAP and ongoing diluted EPS — 2021 $ 0.58 $ 1.25


Diluted Earnings (Loss) Per Share	Three Months Ended March 31
GAAP and ongoing diluted EPS — 2021	$	0.67

Components of change - 2022 vs. 2021
Higher electric revenues, net of electric fuel and purchased power	0.08
Lower effective tax rate (ETR) (a)	0.05
Higher natural gas revenues, net of cost of natural gas sold and transported	0.04
Higher depreciation and amortization	(0.06)
Higher O&M expenses	(0.02)
Higher taxes (other than income taxes)	(0.01)

Higher interest charges	(0.01)
Other, net	(0.04)
GAAP and ongoing diluted EPS — 2022	$	0.70

(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.

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:

Three Months Ended June 30 Six Months Ended June 30
2021 vs. Normal 2020 vs. Normal 2021 vs. 2020 2021 vs. Normal 2020 vs. Normal 2021 vs. 2020
HDD 1.7 % 2.2 % (1.1) % 1.4 % (4.1) % 4.9 %
CDD 6.8 22.4 (26.9) 3.0 22.5 (16.2)
THI 88.9 15.0 67.7 88.4 14.7 67.7


	Three Months Ended March 31
	2022 vs. Normal		2021 vs. Normal		2022 vs. 2021
HDD	9.7	%	1.3	%	8.1	%

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


		Three Months Ended June 30						Six Months Ended June 30							Three Months Ended March 31
		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
Retail electric	Retail electric	$	0.056	$	0.028	$	0.028	$	0.055	$	0.017	$	0.038	Retail electric	$	0.020	$	—	$	0.020
Decoupling and sales true-up	Decoupling and sales true-up	(0.044)		(0.014)		(0.030)		(0.041)		(0.009)		(0.032)		Decoupling and sales true-up	(0.010)		0.002		(0.012)
Electric total	Electric total	$	0.012	$	0.014	$	(0.002)	$	0.014	$	0.008	$	0.006	Electric total	$	0.010	$	0.002	$	0.008
Firm natural gas	Firm natural gas	0.002		0.001		0.001		0.005		(0.006)		0.011		Firm natural gas	0.016		0.003		0.013
Total	Total	$	0.014	$	0.015	$	(0.001)	$	0.019	$	0.002	$	0.017	Total	$	0.026	$	0.005	$	0.021

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


		Three Months Ended June 30											Three Months Ended March 31
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual	Actual											Actual
Electric residential	Electric residential	—	%	6.1	%	(5.6)	%	2.7	%	1.9	%	Electric residential	(1.4)	%	4.7	%	0.3	%	6.2	%	1.9	%
Electric C&I	Electric C&I	6.2		10.1		7.5		11.6		8.3		Electric C&I	2.7		6.6		10.2		4.7		6.2
Total retail electric sales	Total retail electric sales	3.9		8.7		5.2		8.9		6.3		Total retail electric sales	1.2		5.9		8.0		5.2		4.8
Firm natural gas sales	Firm natural gas sales	18.8		(9.5)		N/A		(2.5)		8.3		Firm natural gas sales	(1.5)		20.6		N/A		22.1		6.7


		Three Months Ended June 30											Three Months Ended March 31
		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	0.7	%	(1.6)	%	(1.3)	%	(2.3)	%	(0.7)	%	Electric residential	(1.5)	%	0.4	%	(0.1)	%	0.8	%	(0.3)	%
Electric C&I	Electric C&I	6.5		8.3		8.4		10.2		7.9		Electric C&I	2.7		5.9		10.1		4.1		5.9
Total retail electric sales	Total retail electric sales	4.4		5.0		6.8		6.5		5.3		Total retail electric sales	1.2		4.0		7.8		3.0		3.9
Firm natural gas sales	Firm natural gas sales	12.7		(2.6)		N/A		6.8		7.6		Firm natural gas sales	(1.2)		5.3		N/A		7.3		1.5

Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential 3.2 % 5.6 % 1.8 % 3.8 % 4.0 %
Electric C&I 0.4 1.3 — 4.5 0.9
Total retail electric sales 1.4 2.7 0.3 4.3 1.8
Firm natural gas sales 8.0 (1.9) N/A — 4.4

Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential 2.9% 1.6% 1.4% 0.5% 2.0%
Electric C&I 0.4 0.4 0.2 3.8 0.6
Total retail electric sales 1.2 0.7 0.5 2.8 1.0
Firm natural gas sales 2.4 (1.6) N/A (0.6) 0.9

Six Months Ended June 30 (2020 Leap Year Adjusted)
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential 3.4 % 2.2 % 2.0 % 1.1 % 2.5 %
Electric C&I 1.0 1.0 0.8 4.4 1.2
Total retail electric sales 1.8 1.3 1.0 3.4 1.6
Firm natural gas sales 3.3 (0.7) N/A 0.3 1.8

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~~2022 reflect generally improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector ~~as businesses return~~due to ~~a more normal level. Residential sales remain elevated on a year-to-date basis as individuals working from home have just begun~~increased economic activity. Individuals returning to ~~the office.~~work have led to declines in use per customer and overall residential sales.

•PSCo — Residential sales ~~rose~~declined based on ~~an increase in the number of customers combined with higher~~decreased use per ~~customer. The growth in large C&I sales was primarily led by the service, agriculture, food and energy sectors,~~customer, partially offset by a ~~decrease~~1.2% increase in customers. The growth in C&I sales was due to a 1.3% increase in customers and higher use per customer, primarily the ~~manufacturing sector.~~real estate and leasing, food services, energy and construction sectors.

•NSP-Minnesota — Residential sales growth reflects ana 1.2% increase in ~~the number of~~ customers, ~~combined with higher~~partially offset by decreased use per customer. The growth in C&I sales was primarily due to ~~customer growth 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 an~~declined due to a lower use per customer, partially offset by a 1.0% increase in ~~the number of customers combined with higher use per customer.~~customers. C&I sales increased due to higher use per customer, ~~and growth attributable to the food sector, partially offset~~primarily driven by ~~losses within~~ the energy sector.

•NSP-Wisconsin — Residential sales growth was attributable to ~~customer additions and higher use per customer.~~a 0.7% increase in customers. The growth in C&I sales was due to a 0.4% increase in customers and higher use per customer, primarily led by increases in the manufacturing, accommodation and food services ~~agriculture, food~~ and ~~energy sectors, partially offset by a decrease in the manufacturing sector.~~health care sectors.

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

•Natural gas sales reflect a higher customer use, primarily ~~reflect an~~in NSP-Minnesota and NSP-Wisconsin, as well as a 1.2% increase in ~~the number of~~residential customers ~~combined with slightly higher customer use.~~and a 0.5% increase in C&I customers.

~~Table of Contents~~

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 and ~~margin.~~income taxes.

Electric revenues, fuel and ~~margin:~~

Three Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2021 2020 2021 2020
Electric revenues $ 2,597 $ 2,286 $ 5,467 $ 4,489
Electric fuel and purchased power (1,047) (833) (2,433) (1,630)
Electric margin $ 1,550 $ 1,453 $ 3,034 $ 2,859

~~Changes in~~purchased power and electric margin:

(Millions of Dollars) Three Months Ended June 30, 2021 vs. 2020 Six Months Ended June 30, 2021 vs. 2020
Non-fuel riders $ 89 $ 133
Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota) 34 78
Proprietary commodity trading, net of sharing — Winter Storm Uri — 27
Sales and demand (a)
24 10
Estimated impact of weather (net of decoupling/sales true-up) (1) 5
Wholesale transmission revenue (net) (8) 3
PTCs flowed back to customers (offset by lower ETR) (42) (79)
Other (net) 1 (2)
Total increase in electric margin $ 97 $ 175


	Three Months Ended March 31
(Millions of Dollars)	2022		2021
Electric revenues	$	2,633	$	2,870
Electric fuel and purchased power	(1,094)		(1,386)
Electric margin	$	1,539	$	1,484

Change:


(Millions of Dollars)	Three Months Ended March 31, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, Texas and New Mexico)	$	63
Non-fuel riders	36
Sales and demand(a)	22
Conservation and demand side management (offset in expense)	14

Estimated impact of weather (net of decoupling/sales true-up)	6
PTCs flowed back to customers (offset by lower ETR)	(53)

Proprietary commodity trading, net of sharing(b)	(25)
Comanche Unit 3 outage (c)	(9)
Other (net)	1
Total increase	$	55

(a)Sales excludes weather impact, net of ~~decoupling/~~decoupling in Colorado and proposed sales true-up ~~and demand is net~~mechanism in Minnesota.

(b)Includes $27 million of ~~sales true-up.~~trading margin recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri.

(c)See Other section for further information.

Natural Gas Margin

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

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

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

Three Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2021 2020 2021 2020
Natural gas revenues $ 449 $ 280 $ 1,096 $ 863
Cost of natural gas sold and transported (218) (86) (517) (371)
Natural gas margin $ 231 $ 194 $ 579 $ 492

~~Changes in~~transported and natural gas margin:

(Millions of Dollars) Three Months Ended June 30, 2021 vs. 2020 Six Months Ended June 30, 2021 vs. 2020
Regulatory rate outcomes (Colorado) $ 31 $ 71
Estimated impact of weather 1 8
Other (net) 5 8
Total increase in natural gas margin $ 37 $ 87


	Three Months Ended March 31
(Millions of Dollars)	2022		2021
Natural gas revenues	$	1,090	$	647
Cost of natural gas sold and transported	(710)		(299)
Natural gas margin	$	380	$	348

Table of Contents

Change:


(Millions of Dollars)	Three Months Ended March 31, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Wisconsin, North Dakota)	$	17
Estimated impact of weather	10
Gas sales and transport (excluding weather impact)	7


Other (net)	(2)


Total increase	$	32

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased ~~$50~~$18 million ~~or 9.1%,~~ for the ~~second~~first quarter, ~~and $55 million, or 4.9% year-to-date. Significant changes are summarized as follows:~~

(Millions of Dollars) Three Months Ended June 30, 2021 vs. 2020 Six Months Ended June 30, 2021 vs. 2020
Wind $ 14 $ 22
Information technology and security 13 17
Natural gas systems 6 9
Distribution 9 8
Other 8 (1)
Total increase in O&M expenses $ 50 $ 55

~~The increase was primarily~~ due to additional investments in technology and customer programs, higher insurance premiums and additional bad debt expenses ~~associated with new wind farms, software infrastructure and security costs, natural gas damage prevention, and timing of distribution expenses,~~(primarily attributable to higher billings and/or increased commodity prices), partially offset by ~~continuous improvement initiatives. Quarterly timing impacts also occurred throughout 2020 due to cost control initiatives to mitigate the adverse impact of COVID-19 on sales.~~a reduction in employee benefit costs.

Depreciation and Amortization — Depreciation and amortization increased ~~$55~~$41 million ~~or 11.6%,~~ for the ~~second quarter and $113 million or 12.1% year-to-date.~~first quarter. The increase was primarily driven by several wind farms going into service ~~as well as~~and normal system expansion. ~~In addition, 2021 depreciation expense increased as a result of implementation of new depreciation rates in various states.~~

~~Other Income (Expense)~~ — Other income (expense) decreased $2 million for the second quarter and increased $15 million year-to-date, which was largely related to rabbi trust performance primarily offset in O&M expenses (compensation).

~~AFUDC, Equity and Debt~~ ~~— AFUDC decreased $25 million for the second quarter of 2021 and $40 million year-to-date. The decrease was primarily driven by completion of various wind projects.~~

Interest Charges — Interest charges increased $4$9 million ~~or 1.9%,~~ for the ~~second~~first quarter, ~~and $10 million or 2.5% year-to-date. The increase was~~ largely ~~attributable~~due to ~~higher~~increased long-term debt levels to fund capital investments and ~~a term loan~~the unrecovered/deferred balances related to ~~finance~~ Winter Storm ~~Uri fuel costs, partially offset by lower long-term and short-term interest rates.~~

~~Earnings from Equity Method Investments~~ — Earnings from equity method investments increased $14 million for the second quarter and $17 million year-to-date. The increase was largely attributable to the performance of the EIP funds, which invest in energy technology companies.Uri.

Income Taxes — Income tax benefit increased ~~$25~~$28 million for the ~~second~~first quarter, ~~and $41 million year-to-date. The increase was~~ primarily driven by an increase in wind ~~PTCs due to additional facilities going into service.~~PTCs. 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 higher pretax earnings in 2021.~~

~~Table of Contents~~


~~Other~~

~~Winter Storm Uri~~

In ~~February 2021,~~April 2022, the ~~central portion of~~IRS published inflation factors used to determine the United States experienced a major winter storm (Winter Storm Uri). Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation across the region. 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.

PTC rate. As a result, the 2022 PTC rate on the sale 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. Certain energy transactions are subject to final/settlement calculation adjustments, including the impacts of credit losses shared among market participants.

~~Total incurred costs (net)~~electricity produced from wind is 2.7 cents per ~~operating utility:~~


~~(Millions of Dollars)~~
~~NSP-Minnesota~~	$	~~230~~
~~NSP- Wisconsin~~	45
~~PSCo~~	~~610~~
~~SPS~~	~~100~~
~~Total~~	$	~~985~~

In addition, higher market prices resulted in $27 million of net gains (after customer sharing) related to proprietary commodity trading. These transactions were primarily entered into under Xcel Energy’s ordinary trading practices prior to Winter Storm Uri.

~~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 27 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 $179 million in incremental costs from natural gas customers over 27 months with no financing charge and an additional $36 million from natural gas customers through the standard 12 month true-up. Parties were generally supportive of the proposed recovery period commencing Sept. 1, 2021. The DOC recommended disallowances of $21 million; the OAG recommended disallowances of $34 million. A MPUC decision on the start of cost recovery is expected prior to Sept. 1, 2021. A proceeding related to the proposed disallowances is expected to continue into 2022.
	~~South Dakota~~	In April, NSP-Minnesota filed a letter with the South Dakota Public Utilities Commission (SDPUC) proposing no impact to the fuel clause as we were a net seller in the electric market. The SDPUC has approved the proposal.
	~~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 natural gas costs incurred during Storm Uri 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.~~
~~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. A decision is expected in the first quarter of 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery.
~~SPS~~	~~Texas~~	SPS filed for a surcharge in the second quarter to recover $62 million in fuel costs over 24 months, subject to revision due to re-settlements. Prudence of costs will be subject to review in SPS's upcoming fuel reconciliation case.
	~~New Mexico~~	~~The NMPRC approved SPS's request to recover $26 million of fuel costs over 24 months with no financing charge, subject to revision due to re-settlements and 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 and any potential re-shut downs or reinstatement of business restrictions both domestically and globally.~~

~~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 askilowatt hour, 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, 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. As part of NSP-Minnesota’s electric rate case stay-out alternative, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related costs.

~~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. The Company continues to monitor the availability of materials and seek alternative suppliers as necessary.2.5 cents for 2021.


Public Utility Regulation and Other

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and ~~WGI.~~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~~ F ~~orm 10-Q~~ ~~for the quarterly period ended March 31,~~ 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 North Dakota Electric Rate Case~~

~~$19~~

~~November 2020~~

~~Pending~~

~~2020 TCR Electric Rider~~

~~November 2019~~

~~Pending~~

~~2021 GUIC Natural Gas Rider~~

~~October 2020~~

~~Pending~~

~~2020 RES Electric Rider~~

~~107~~

~~November 2019~~

~~Received~~

~~2021 RES Electric Rider~~

~~189~~

~~November 2020~~

~~Pending~~

~~Additional Information:~~

~~2020 North Dakota~~2022 Minnesota Electric Rate Case —~~In November 2020,~~ In October 2021, NSP-Minnesota filed a three-year electric rate case with the ~~NDPSC. NSP-Minnesota requested an increase in annual retail electric revenues of approximately $19 million.~~MPUC. The rate ~~filing was~~case is based on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years.

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 December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022.

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

•Intervenor testimony: Oct. 3, 2022.

•Rebuttal testimony: Nov. 8, 2022.

•Hearing: Dec. 13-16, 2022.

•ALJ Report: March 31, 2023.

•MPUC Order: June 30, 2023.

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 $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 ~~an electric~~a rate base of ~~approximately $677~~$934 million. ~~Interim~~

In December 2021, the MPUC approved interim rates of $25 million, subject to refund, ~~of approximately $13 million~~effective Jan. 1, 2022.

Next steps in the procedural schedule are ~~currently in effect.~~

~~In July 2021, NSP-Minnesota and various parties filed an uncontested settlement agreement, which includes:~~expected to be as follows:

•~~Base revenue increase of $7 million.~~Intervenor testimony: Aug. 30, 2022.

•~~ROE of 9.5%.~~Rebuttal testimony: Oct. 4, 2022.

•~~Equity ratio of 52.5%.~~Hearing: Nov. 1-4, 2022.

•~~Deferral of advanced grid intelligence and security initiative capital and O&M expenses.~~ALJ Report: Feb. 6, 2023.

•~~An earnings cap mechanism, which would return to customers 100% of earnings equal to or in excess of 9.75% ROE, effective until the next rate case.~~

~~A NDPSC decision on the settlement and implementation is anticipated in the fourth quarter of 2021.~~

~~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.~~Order: April 26, 2023.

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

~~2020 RES Electric Rider~~Rate Case — In November 2019, NSP-Minnesota filed the RES Rider. In March 2021, the MPUC voted to approve revenue requirements of $41 million for 2019 and $66 million for 2020. The filing included a ROE of 9.06%. The new rate will be implemented after an MPUC order is issued.

~~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 Minnesota Electric Rate Case and Stay-Out Alternative~~ — In November 2020, NSP-Minnesota filed an electric rate case seeking a $597 million revenue increase over three years with the MPUC. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing. In December 2020, the MPUC verbally approved the stay-out alternative petition.

~~In February~~September 2021, NSP-Minnesota filed a ~~letter highlighting~~request with the NDPSC for a ~~change in the calculation~~natural gas rate increase of ~~its total deficiency~~$7 million, or 10.5%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and ~~interim~~a rate base of $124 million. Interim rates ~~included in its November 2020 filing. This adjustment would have reduced the filed deficiency and interim rates by approximately $43~~of $7 million, ~~should the rate case have proceeded, but has no impact~~subject to refund, were implemented on ~~the stay-out alternative petition.~~Nov. 1, 2021.

In April ~~2021, the MPUC issued~~2022, NDPSC Staff recommended a $4 million increase, based on an ~~order approving NSP-Minnesota’s proposed changes~~ROE of 9.5% and an equity ratio of 52.0%. In April 2022, NSP-Minnesota updated its request to $6 million, or 8.8% based on a ~~requirement to withdraw NSP-Minnesota’s notice~~requested ROE of ~~change in rates, as well as establishing a comment period allowing parties to address the changes discussed~~10.5%, an equity ratio of 52.54% and an updated rate base of $115 million. Hearings are expected June 1-3, 2022. An NDPSC decision is expected in the ~~February letter. In June 2021, the MPUC issued an order denying a request for reconsideration~~third quarter of ~~the rate case stay-out approval.~~2022.

2722

Table of Contents

Minnesota ~~Resource Plan~~ —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The initial plan was expected to result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050. Parties submitted comments in February 2021 and there was significant opposition to the proposal to build a Sherco combined cycle natural gas plant and associated pipeline infrastructure.

In June 2021, NSP-Minnesota filed an alternative plan that would reduce carbon emissions 85% by 2030 and has a lower projected cost than either of the previously submitted plans. The alternative plan includes the following:

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

•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.~~

~~Supplemental comments are due Aug 13, 2021. The MPUC is anticipated to make a final decision in late 2021 or early 2022.~~

~~Minnesota~~ Relief and Recovery — 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 and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years.

•In April 2021, NSP-Minnesota proposed to add 460 ~~MWs~~MW of solar facilities at the Sherco site with an incremental investment of approximately $575 million. ~~A MPUC decision is expected in late 2021 or early 2022.~~See further discussion within Sherco Solar Project below.

•In ~~June 2021,~~March 2022, the MPUC approved the public charging proposal for 21 sites and asked NSP-Minnesota to develop a proposal for additional investments in public charging infrastructure, but denied NSP-Minnesota’s proposal to ~~acquire a 120~~provide $40 million of electric vehicle rebates due to concerns regarding legal authority.

Minnesota Resource Plan Settlement—In July 2019, NSP-Minnesota filed its Minnesota (Upper Midwest) resource plan, which runs through 2034. In February 2022, the MPUC approved the following:

•10-year extension for the Monticello nuclear facility.

•Retirement of the A.S. King plant in 2028 and Sherco 3 in 2030.

•NSP-Minnesota ownership of Sherco and A.S. King gen-tie lines plus additional renewable resources on the lines up to its current interconnection rights (2,000 MW ~~repowered wind farm from ALLETE~~ for ~~$210 million.~~Sherco and 600 MW for A.S. King).

•The need for 2,150 MW of new wind and 2,500 MW of new solar by 2032, as well as additional renewable generation of 1,100 MW beyond 2032.

•Recognition of the need for 800 MW of additional firm dispatchable resources between 2027 and 2029. The dispatchable generation will require an approval through a certificate of need process.

2022 RES Electric Rider — In November 2021, NSP-Minnesota filed the RES Rider. The requested amount of $264 million includes a true-up (2020 and 2021 riders) of $154 million and the 2022 requested amount of $110 million. The filing included an ROE of 9.06%. An MPUC decision is ~~also considering NSP-Minnesota’s proposal to provide $150~~pending.

2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The amount of $189 million included a true-up (2019 and 2020 riders) of ~~incremental electric vehicle rebates.~~$96 million and a 2021 amount of $93 million. The filing was based on an ROE of 9.06%. The rider was approved by the MPUC in March 2022.

2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on an ROE of 9.04%. An MPUC decision is pending.

2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on an ROE of 9.04%. An MPUC decision is pending.

2022 TCR Electric Rider — In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million based on an ROE of 9.06%. An MPUC decision is pending.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~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

Recently Concluded Regulatory Proceedings

~~NSP-Wisconsin Solar Proposal~~Michigan Electric Rate Case — In ~~June 2021,~~March 2022, the ~~PSCW~~Michigan Public Service Commission approved ~~NSP-Wisconsin’s request to purchase the 74 MW Western Mustang build-own-transfer solar facility for approximately $100 million. The project is scheduled to go into service~~a settlement that grants NSP-Wisconsin an electric revenue increase of $1.6 million in ~~2023.~~

~~NSP-Wisconsin Electric and Natural Gas Settlement~~ ~~— In July 2021, NSP-Wisconsin filed an application with the PSCW seeking approval~~2022, based on a ROE of ~~a rate case settlement with various intervenors for 2022-2023.~~

~~The settlement agreement increases electric rates by $35 million (4.9%) for 2022~~9.7% and an ~~incremental $18 million increase (2.5%) for 2023. For the natural gas utility, rates increase by $10 million (8.4%) for 2022 and 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 2022 and 2023.~~. New rates were effective April 1, 2022.

•~~Returning $9 million in various net regulatory liabilities to offset customer impacts in 2023.~~

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

•~~Addressing COVID-19 deferral recovery in 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 decision is anticipated in the fourth quarter of 2021.~~

PSCo

Pending and Recently Concluded Regulatory Proceedings

~~Proceeding~~

Amount
(in millions)

Filing
Date

~~Approval~~

~~PSIA Extension~~

~~$464~~

~~February 2021~~

~~Pending~~

~~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. 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. The Staff and OCC have recommended the CPUC deny the extension of the rider. However, if the CPUC were to allow the rider extension, the scope of the rider would be limited and only allow a return on debt. A CPUC decision is expected in the fourth quarter of 2021.

Colorado ~~Electric~~Natural Gas Rate ~~Request~~Case — — In ~~July 2021,~~January 2022, PSCo filed a request with the CPUC seeking a net increase to retail ~~electric base rate revenue~~natural gas rates of ~~$343 million (or 12.4%).~~$107 million. The total ~~request~~change to base rates is $215 million, which reflects ~~a $470~~the transfer of $108 million ~~increase, which includes $127 million of~~ previously ~~authorized costs currently~~ recovered from customers through ~~various rider mechanisms.~~the PSIA rider. The request is based on a ~~10.0%~~10.25% ROE, an equity ratio of ~~55.64%~~55.66% and a 2022 ~~forecast test year. The request also includes impacts of a new depreciation study. A required~~current test year ~~including~~with a ~~10.5% ROE, was also filed. Rates are expected~~projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022.

Additionally, PSCo’s request includes step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to ~~be effective April 9, 2022.~~continued capital investment.

~~Table of Contents~~


Revenue Request (millions of dollars)	2022
Changes since ~~2019~~2020 rate case:
~~Plant-related growth~~Plant related investments (a)	$	95210
~~AGIS~~Operations and maintenance, amortization and other expenses	7311
~~Updated cost of capital~~Property tax expense	5311
~~New depreciation rates~~Sales growth	43
~~Wildfire mitigation~~	25
~~Property taxes~~	25
~~Amortization of previously approved deferrals~~	17
~~Other~~	12 (17)
Net increase to revenue	~~343~~215
~~Roll-in of previously~~Previously authorized costs:
~~TCA~~Transfer of costs previously recovered through the PSIA rider ~~revenues and Cheyenne Ridge costs~~	~~127~~ (108)
Total base revenue request	$	~~470~~107


~~Expected average~~Projected 2022 year-end rate base (billions of dollars)	$	~~10.3~~3.6

(a) Includes approximately $28 million as a result of the increase in ROE from 9.2% to 10.25%.

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

•Intervenor testimony: June 15, 2022.

•Rebuttal testimony: July 13, 2022.

•Settlement: Aug. 3, 2022.

•Evidentiary hearings: Aug. 17-23, 2022.

•Statement of position: Sept. 21, 2022.

Colorado Electric Rate Request— In July 2021, PSCo filed a request with the CPUC seeking a net electric rate increase of $343 million (or 12.4%). The total request reflects a $470 million increase, which includes $127 million of previously authorized costs currently recovered through various rider mechanisms. The request was 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.

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In March 2022, the CPUC approved an unopposed settlement without modification. Rates became effective April 1, 2022. Key settlement terms include:

•A net electric rate increase of $177 million. The total change in base rates is $299 million, which includes $122 million of revenue previously collected through various rider mechanisms.

•A ROE of 9.3% and an equity ratio of 55.69%.

•A current 2021 test year (average rate base) with the transfer of Cheyenne Ridge, the Wildfire Mitigation Plan and Advanced Grid Intelligence and Security investments at year-end rate base.

•Approval of all of PSCo’s proposed depreciation adjustments.

•Continuation of the property tax, qualified pension, and non-qualified pension trackers.

•Continuation of Advanced Grid Intelligence and Security deferral including interest equivalent to PSCo's weighted average cost of capital once the balance exceeds $50 million.

•Continuation of the Wildfire Mitigation Plan deferral, with a debt return.

Colorado Power Pathway Settlement— In February 2022, the CPUC approved 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 Performance Incentive Mechanism 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. Key details of the Performance Incentive Mechanisms are pending the CPUC’s written decision.

•The CPUC granted a conditional CPCN 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 April 2022, PSCo and multiple intervenors filed a revised settlement of the resource plan, 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. A CPUC decision is expected in the second 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 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 comprehensive settlement with the CPUC Staff and the Colorado Energy Office, which proposed to address four outstanding regulatory items, including recovery of fuel costs related to Winter Storm Uri, disputed revenue 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 Utility Consumer Advocate has not signed the settlement. A hearing and a CPUC decision on the settlement is expected in the second quarter of 2022.

Key settlement terms include:

•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 no carrying charges through a rider mechanism. Recovery will likely commence in Q2 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 (approved by the CPUC in February 2022 as part of the 2020 retail electric commodity adjustment settlement agreement).

•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 Dec. 31, 2021.

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

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

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

Comanche Unit 3 — In October 2021, a comprehensive settlement was reached, which addressed treatment of 2020 Comanche Unit 3 replacement power costs. See Colorado Partial Settlement disclosure above and Note 10 accompanying the consolidated financial statements for further information.

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, oil and gas royalty revenues, Board of Directors equity compensation and a true-up surcharge to collect the difference between ~~what~~ rates ~~should have been in place~~ from February through August ~~2020 (based on~~2020. In January 2022, the Denver District Court issued its decision that the CPUC’s ~~decision~~approach to gains and losses on certain sales of assets was legally erroneous and confiscatory to PSCo and set aside and remanded the ~~Company’s Application~~issue for ~~Reconsideration, Rehearing or Reargument) and what rates were actually in place. Briefing was completed on July 9, 2021 and a decision is pending.~~

~~2017 Natural Gas Rate Case Appeal~~ — In April 2019, PSCo filed an appeal of the CPUC’s ruling regarding PSCo’s natural gas rate case. In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but it upheld the CPUC treatment of the retiree medical assets and capital structure methodology. In July 2021, the CPUC approved a weighted average cost of capital return for the applicable period of Jan. 1, 2018 through Oct. 31, 2020.

~~Decoupling Filing~~— PSCo's 2019 Electric Rate Case included 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 June 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.

~~Colorado’s Power Pathway Transmission Expansion~~ — In March 2021, PSCo filed for a Certificate of Public Convenience and Necessity for the Power Pathway transmission project, proposing a 560-mile, 345 kilovolt double circuit transmission network 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 extension of the Power Pathway project into southeast Colorado, referred to as the May Valley - Longhorn Extension ($0.3 billion). PSCo expects future filings for related network upgrades, voltage support and interconnection facilities, which with the May Valley - Longhorn Extension, could result in an incremental investment of $0.5 - $0.8 billion. ~~A CPUC decision regarding the Power Pathway project, as well as the May Valley - Longhorn Extension, is expected by February 2022.~~

~~PSCo KEPCO Filing~~ —In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. However, the ALJ ruled against approval of the Termination Agreement. In July 2021, the CPUC upheld the ALJ’s recommended decision.further consideration. PSCo anticipates filing ~~an Application~~a Motion for ~~Reconsideration.~~

~~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.

~~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 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.

~~A CPUC decision on the resource plan is expected in January of 2022 with the competitive solicitation for resource additions expected~~Decision in Q2 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 plant. 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.

2924

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GCA NOPR—In ~~October 2020,~~June 2021, the CPUC ~~initiated~~issued a ~~non-adjudicatory review~~NOPR addressing the recovery of ~~Comanche Unit 3’s performance. A report on performance was issued in March 2021.~~costs through the GCA. The CPUC ~~Staff’s report noted higher-than average outages~~has reopened the GCA NOPR matter and ~~included some criticisms of PSCo’s operations of Comanche Unit 3 over~~proposed a 2 step process aimed at 1) considering near term process changes to the ~~last ten years. The report recommended thorough explanation of the future of Comanche Unit 3 operations in the next resource plan,~~GCA used by various utilities to be filed no later than July 1, 2022 and 2) a longer term process to evaluate potential performance ~~standards for all company-owned generation and a review of outage and repair costs in the upcoming proceedings.~~

~~In February 2021, the joint owners of Comanche Unit 3 (Intermountain Rural Electric Association and Holy Cross Electric) served PSCo with a notice of claim related~~incentive GCA structures to ~~Comanche Unit 3's operation and availability.~~ ~~Discussions are proceeding pursuant to a contractual dispute resolution process and the amount of any alleged damages depends on multiple factors and is currently unknown.~~be filed no later than Nov. 1, 2022.

SPS

Pending and Recently Concluded Regulatory Proceedings

~~Proceeding~~

Amount
(in millions)

Filing
Date

~~Approval~~

~~2021 New Mexico Electric Rate Case~~

~~$88~~

~~January 2021~~

~~Pending~~

~~2021 Texas Electric Rate Case~~

~~$143~~

~~February 2021~~

~~Pending~~

~~Additional Information:~~

2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC ~~seeking an increase in base rates of approximately $88 million. SPS' net rate increase to New Mexico customers is expected to be approximately $48 million, or 10%, as~~with a ~~result of the offsetting fuel cost reductions and PTCs from the Sagamore wind project. PTCs are credited to customers through the fuel clause. In June 2021, SPS revised its~~current requested base rate increase toof $84 million.

~~The request was based on~~In February 2022, the NMPRC approved an uncontested stipulation without modification, which reflected a ~~historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021,~~$62 million rate increase, a ~~ROE~~change in the depreciation life of ~~10.35%,~~the Tolk coal plant to 2032, 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)~~reconciliation statements and determining the revenue requirements for the Sagamore and 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.~~

~~A public hearing is scheduled for July~~projects. New rates went into effect on Feb. 26, ~~- Aug. 6, 2021. A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.~~2022.

2021 Texas Electric Rate Case — In ~~February~~ 2021, SPSfiled an electric rate case with the PUCT and its municipalities seeking an increase in base rates of approximately ~~$143~~$140 million. SPS' net rate increase to Texas customers is expected to be approximately $74 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 iswas 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~~12-months ended Dec. 31, 2020.

~~The request includes the effect of losing approximately 400 MW from~~In January 2022, SPS and intervenors filed 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).~~

~~Procedural schedule expected to be as follows:~~blackbox settlement. Key terms include:

•~~Intervenor testimony — Aug. 13, 2021.~~

•~~Staff testimony — Aug. 20, 2021.~~

•~~Rebuttal testimony — Sept.~~Base rate increase of $89 million effective back to March 15, 2021.

•~~Public hearing — Oct. 18 - Oct. 28, 2021.~~A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.

~~The PUCT set current~~•Depreciation lives for Tolk moved up to 2034 and Harrington coal assets moved up to 2024.

In February 2022, the ALJ issued an order approving interim rates ~~as temporary as of~~effective March ~~15, 2021. Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates.~~1, 2022. A PUCT decision is expected in the ~~first~~second quarter of 2022.

Other

Supply Chain

Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the availability of materials and has sought to mitigate impacts by seeking alternative suppliers as necessary.

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.

The uncertainty of the investigation and the adverse impact on potential tariffs has resulted in the cancellation or delay of certain domestic solar projects.

The impacts on Xcel Energy are as follows:

~~New Mexico Integrated Resource Plan~~•NSP-Minnesota Sherco Solar Project— In April 2021, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an initial estimated investment of approximately $575 million. NSP-Minnesota requested a delay in the procedural schedule due to recent solar supply chain disruptions and potential impact on pricing. We now anticipate a MPUC decision in Q4 2022 or Q1 2023. The proposed facilities are still expected to be in-service by the end of 2025.

•NSP-Wisconsin — In June 2021, the Public Service Commission of Wisconsin approved NSP-Wisconsin’s Western Mustang solar project, a 74 MW facility that would be built by a developer for approximately $100 million. The project was originally scheduled to go into service in 2022. As a result of the disruption of the solar supply chain, the developer has indicated difficulty delivering the project at the contract price and scheduled in-service date. Negotiations on a potential solution are on-going.

•PSCo PPAs— PSCo has several solar PPAs scheduled to go into service in late 2022 and early 2023. Some developers have indicated difficulty delivering the projects at the contract price and at the scheduled in-service date. Negotiations on a potential solution are on-going. PSCo is developing contingency plans in the event that the PPAs are not completed in time to meet the capacity needs of the 2023 summer season.

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.

On March 31, 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.

Comanche Unit 3 Outage

In January 2022, PSCo experienced an extended outage at the Comanche Unit 3 plant (750 MW, coal-fueled electric generating unit).PSCo will not seek recovery of any incremental replacement power costs, which are estimated to be approximately $25 million, assuming normal weather, current market pricing and remediation in June 2022. Incremental replacement power costs incurred as of March 31, 2022 were $9 million.

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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 $1 billion (largely deferred as regulatory assets).

Regulatory Overview — In July 2021, SPS filed an IRP with the NMPRC, as required every three years. SPS is forecasting sufficient resources through 2025. A projected capacity deficit was identified totaling approximately 174 MW in 2031, increasing to 4,194 MW by 2041.

~~SPS~~Xcel Energy has ~~provided a number of alternatives, including a proposed portfolio of resources incorporating the addition of wind generation, solar generation, firm and dispatchable peaking generation,~~natural gas, fuel and purchased ~~power agreements. SPS will continue~~energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to ~~evaluate~~63 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers. Xcel Energy currently has approval for recovery of Winter Storm Uri costs in Wisconsin, Michigan, North Dakota and New Mexico. There were no material costs for South Dakota.

A summary of the pending regulatory requests for Winter Storm Uri cost recovery in the other ~~options including energy storage and emerging technologies, taking into consideration cost-effectiveness. The IRP~~states is ~~subject to public comment and potential public hearings and will ultimately be reviewed by the NMPRC for approval.~~listed below.

Proceedings initiated:


Utility Subsidiary	Jurisdiction	Regulatory Status
NSP-Minnesota	Minnesota	In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021. 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. The $179 million in extraordinary cost recovery is subject to refund pending the outcome of a contested case before an ALJ. In December 2021, direct testimony was received from intervenors. A hearing before the ALJs took place in February 2022. The Company and intervenors subsequently submitted briefs. The DOC recommended that NSP-Minnesota be disallowed $122 million in costs. The OAG modified its position, recommending disallowances of $110 million to $148 million, and the CUB continues to recommend a $69 million disallowance. Xcel Energy strongly disagrees with the recommendations of the DOC, OAG and CUB and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. An ALJ decision is expected in late May and an MPUC decision is expected in Q3 of 2022.


Utility Subsidiary	Jurisdiction	Regulatory Status
PSCo	Colorado	In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge. In October, a partial settlement was reached with the Staff and the Colorado Energy Office, allowing full recovery of Winter Storm Uri deferred costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with no carrying charges. A CPUC decision on the settlement is pending. The statutory date for decision is July 15, 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery.
SPS	Texas	In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing. In January 2022, SPS and other parties filed a stipulation for interim rates. The filing covers all fuel under-collections occurring between January 2020 and August 2021, totaling $121 million. The settlement does not address the prudence of Winter Storm Uri costs nor the retention of $11 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. Interim rates, designed to collect up to $110 million over a period of 30 months, began on Feb. 1, 2022.

Environmental

Affordable Clean Energy

In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans by 2022 for greenhouse gas reductions from coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision ~~if not successfully appealed or reconsidered,~~ would allow the EPA to proceed with alternate regulation of coal-fired power plants. However, the Court of Appeals decision has been appealed to the U.S Supreme Court, where the Court heard argument in February and is expected to rule by June on the nature and extent of the EPA’s greenhouse gas regulatory authority. If ~~the~~any new rules require additional investment, Xcel Energy believes ~~based on prior state commission practices,~~ that the cost of these initiatives or replacement generation would be recoverable through ~~rates.~~

~~Emerging Regulation~~

New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the environment. These chemicals have received heightened attention by environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal,rates based on prior state 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 results of operations, financial condition or cash flows. Xcel Energy will continue to monitor these regulatory developments and their potential impact on its operations.

commission practices.

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

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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 ~~June 30, 2021:~~March 31, 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)	$	(7)	$	(2)	$	1	$	1	$	(7)	NSP-Minnesota (a)	$	(7)	$	(11)	$	(3)	$	(2)	$	(23)
NSP- Minnesota (b)	NSP- Minnesota (b)	2		4		(10)		—		(4)		NSP- Minnesota (b)	4		4		(5)		(5)		(2)
PSCo (a)	PSCo (a)	4		3		—		—		7		PSCo (a)	16		9		2		1		28
PSCo (b)	PSCo (b)	(35)		(60)		(1)		—		(96)		PSCo (b)	(41)		(45)		1		—		(85)
		$	(36)	$	(55)	$	(10)	$	1	$	(100)		$	(28)	$	(43)	$	(5)	$	(6)	$	(82)


		Options Maturity											Options Maturity
(Millions of Dollars)	(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	NSP-Minnesota (b)	$	—	$	—	$	—	$	4	$	4	NSP-Minnesota (b)	$	1	$	—	$	—	$	11	$	12
PSCo (b)	PSCo (b)	22		39		—		—		61		PSCo (b)	25		24		—		—		49
		$	22	$	39	$	—	$	4	$	65		$	26	$	24	$	—	$	11	$	61

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

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

Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the ~~six~~three months ended ~~June 30:~~March 31:


(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	(37)		(7)		Contracts realized or settled during the period	3		(33)
Commodity trading contract additions and changes during the period	Commodity trading contract additions and changes during the period	56		7		Commodity trading contract additions and changes during the period	9		37
Fair value of commodity trading net contracts outstanding at June 30		$	(35)	$	(59)
Fair value of commodity trading net contracts outstanding at March 31						Fair value of commodity trading net contracts outstanding at March 31	$	(21)	$	(50)

At ~~June 30, 2021,~~March 31, 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 ~~$19~~$14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately ~~$19~~$17 million. At ~~June 30, 2020,~~March 31, 2021, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately ~~$12~~$14 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately ~~$12~~$13 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 on 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)	(Millions of Dollars)	Three Months Ended June 30		VaR Limit		Average		High		Low		(Millions of Dollars)	Three Months Ended March 31		VaR Limit		Average		High		Low
2022												2022	$	1.1	$	3.0	$	1.0	$	1.3	$	0.7
2021	2021	$	1.7	$	3.0	$	1.2	$	1.9	$	0.7	2021	0.5		3.0		2.9		52.3		0.5
2020		0.8		3.0		0.9		1.1		0.6

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.

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 to assess if further actions are required to assure a secure supply of enriched nuclear ~~material supplied from Russia. Long-term, through 2030,~~material. NSP-Minnesota is scheduled to take delivery of approximately 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 ~~June 30,~~March 31, 2022 and 2021, ~~and 2020,~~ 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~~$12 million and ~~$14~~$15 million, respectively.

~~Table of Contents~~

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

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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 ~~June 30, 2021,~~March 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$64~~$39 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of ~~$24~~$28 million. At ~~June 30, 2020,~~March 31, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$27~~$34 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $2$12 million.

Xcel Energy conducts credit reviews for all counterparties and employs credit risk control, 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 ~~June 30, 2021.~~March 31, 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 ~~June 30, 2021.~~March 31, 2022.


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Operating Cash Flows


(Millions of Dollars)	~~Six~~Three Months Ended ~~June 30~~March 31
Cash ~~provided by~~used in operating activities — ~~2020~~2021	$	~~1,148~~ (136)

Components of change — ~~2021~~2022 vs. ~~2020~~2021
Higher net income	9118
Non-cash transactions (a)	1815
Changes in working capital (b)	~~(35)~~(36)
Changes in net regulatory and other assets and liabilities	~~(733)~~1,279
Cash provided by operating activities — ~~2021~~2022	$	~~489~~1,140

(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 $659~~increased $1,276 million for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared with the prior year. ~~Decrease~~The increase was primarily due to the deferral of net natural gas, fuel and purchased energy costs related to Winter Storm Uri in the first ~~quarter.~~quarter of 2021.

Investing Cash Flows


(Millions of Dollars)	~~Six~~Three Months Ended ~~June 30~~March 31
~~Cash used in investing activities — 2020~~	$	~~(2,580)~~

~~Components of change — 2021 vs. 2020~~
~~Decreased capital expenditures~~	~~602~~
~~Other investing activities~~	~~(224)~~
Cash used in investing activities — 2021	$	~~(2,202)~~(1,035)

Components of change — 2022 vs. 2021
Decreased capital expenditures	82

Other investing activities	1
Cash used in investing activities — 2022	$	(952)

Net cash used in investing activities decreased ~~$378~~$83 million for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared with the prior year. The decrease in capital expenditures was largely due to timing and the ~~purchase~~completion of ~~MEC in January 2020, which was subsequently sold in July 2020.~~various wind projects.

Financing Cash Flows


(Millions of Dollars)	~~Six~~Three Months Ended ~~June 30~~March 31
~~Cash provided by financing activities — 2020~~	$	~~2,818~~

~~Components of change — 2021 vs. 2020~~
~~Lower debt issuances~~	~~(280)~~
~~Higher repayments of long-term debt~~	~~(399)~~
~~Higher dividends paid to shareholders~~	~~(39)~~
~~Other financing activities~~	22
Cash provided by financing activities — 2021	$	~~2,122~~ 2,081

Components of change — 2022 vs. 2021
Lower debt issuances	(2,723)
Lower repayments of long-term debt	400
Higher dividends paid to shareholders	(17)
Other financing activities	(5)
Cash used in financing activities — 2022	$	(264)

Net cash provided by (used in) financing activities decreased ~~$696~~$2,345 million for the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022 compared with the prior year. The decrease was primarily attributable to the amount/timing of ~~short-term~~debt issuances and ~~long-term debt issuances.~~

repayments, partially attributable to deferral of Winter Storm Uri costs in 2021 and pending recovery in 2022 and beyond.

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Capital Requirements

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

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

•In January ~~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 revolving credit facility for two additional one-year periods beyond the June 2024 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

As of ~~July 26 2021, Xcel~~ April 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	$	508	$	742	$	—	$	742	Xcel Energy Inc.	$	1,250	$	641	$	609	$	1	$	610
PSCo	PSCo	700		9		691		3		694		PSCo	700		133		567		3		570
NSP-Minnesota	NSP-Minnesota	500		9		491		226		717		NSP-Minnesota	500		11		489		3		492
SPS	SPS	500		13		487		2		489		SPS	500		256		244		2		246
NSP-Wisconsin	NSP-Wisconsin	150		—		150		2		152		NSP-Wisconsin	150		50		100		1		101
Total	Total	$	3,100	$	539	$	2,561	$	233	$	2,794	Total	$	3,100	$	1,091	$	2,009	$	10	$	2,019

(a)Credit facilities expire in June 2024.

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

Bilateral Credit Agreement

In April ~~2021, the~~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 ~~June 30, 2021,~~March 31, 2022, NSP-Minnesota’s outstanding letters of credit under the ~~Bilateral Credit Agreement~~bilateral credit agreement were as follows:


(Millions of Dollars)	(Millions of Dollars)	Limit		Amount Outstanding		Available		(Millions of Dollars)	Limit		Amount Outstanding		Available
NSP-Minnesota	NSP-Minnesota	$	75	$	75	$	—	NSP-Minnesota	$	75	$	45	$	30

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 billion for Xcel Energy Inc.

•$700 million for PSCo.

•$500 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.~~

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 June 30, 2021			Year Ended Dec. 31, 2020			(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2022			Year Ended Dec. 31, 2021
Borrowing limit	Borrowing limit	$	4,300		$	3,100		Borrowing limit	$	3,100		$	3,100
Amount outstanding at period end	Amount outstanding at period end	1,745			584			Amount outstanding at period end	996			1,005
Average amount outstanding	Average amount outstanding	1,521			1,126			Average amount outstanding	1,061			1,399
Maximum amount outstanding	Maximum amount outstanding	1,745			2,080			Maximum amount outstanding	1,357			2,054
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	0.66		%	1.45		%	Weighted average interest rate, computed on a daily basis	0.42		%	0.57		%
Weighted average interest rate at period end	Weighted average interest rate at period end	0.58			0.23			Weighted average interest rate at period end	0.93			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.

~~2021~~2022 Planned Financing Activity — During ~~2021,~~2022, Xcel Energy plans to issue ~~approximat~~approximately ~~ely $75~~$75 to $80 million ofof equity through the DRIP and benefit ~~programs. Xcel Energy Inc. and its utility subsidiaries issued or anticipate issuing the following.~~

Issuer Security Amount Status Tenor Coupon
PSCo First Mortgage Bonds $ 750 million Completed 10 Year 1.875 %
SPS First Mortgage Bonds 250 million Completed 29 Year 3.15
NSP-Minnesota First Mortgage Bonds 425 million Completed 10 Year 2.25
NSP-Minnesota First Mortgage Bonds 425 million Completed 31 Year 3.20
NSP-Wisconsin First Mortgage Bonds 100 million
Q3 (a)
30 Year 2.82 %

~~(a)~~ programs~~The NSP-Wisconsin private placement first mortgage bond has been priced and is expected to close on July 30, 2021.~~

. In addition, Xcel Energy may issue ~~a holding company bond~~up to $800 million in equity from 2022-2026. Xcel Energy and its utility subsidiaries plan to issue the ~~fourth quarter~~following:

Issuer

Security

Amount

Status

Xcel Energy

Unsecured Bonds

700

million

Planned - Q2

PSCo

First Mortgage Bonds

700

million

Planned - Q2

SPS

First Mortgage Bonds

200

million

Planned - Q2

NSP-Minnesota

First Mortgage Bonds

500

million

Planned - Q2

NSP-Wisconsin

First Mortgage Bonds

100

million

Planned - Q3

Financing plans are subject to ~~pay down the outstanding term loan.~~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.

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

Xcel Energy ~~2021~~2022 Earnings Guidance — — Xcel Energy’s ~~2021~~2022 GAAP and ongoing earnings guidance is a range of ~~$2.90~~$3.10 to ~~$3.00~~$3.20 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% to 2%.

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

•Capital rider revenue is projected to increase ~~$100~~$0 million to ~~$110~~$10 million (net of PTCs). The change in the capital rider assumption reflects an increase in the PTC rate, as published by the IRS in April 2022, and will not materially impact earnings as it will be offset by lower tax expense. PTCs are credited to customers through capital riders ~~fuel clause or base rates~~ and ~~results in a reduction~~reductions to ~~electric margin.~~other regulatory mechanisms.

•O&M expenses are projected to increase ~~0% to~~approximately 1%.

•Depreciation expense is projected to increase approximately ~~$155~~$285 million to ~~$165~~$295 million. The change in assumption is a result of new rates going into effect in Colorado and New Mexico for changes in depreciation lives and will be offset by revenue with minimal impact on earnings.

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

•Interest expense (net of AFUDC - debt) is projected to increase ~~$20~~$80 million to ~~$30~~$90 million. The assumption change reflects higher interest rates and slightly larger debt issuances.

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

•ETR is projected to be ~~(7%~~~(6%) to (8%). The change in the ETR assumption reflects ~~benefits~~an increase in the PTC rate, as published by the IRS in April 2022. The impacts 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 ~~2020~~2021 base of ~~$2.78~~$2.96 per share, which represents the mid-point of the ~~original 2020~~revised 2021 guidance range of ~~$2.73~~$2.94 to ~~$2.83~~$2.98 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 ~~June 30, 2021,~~March 31, 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~~PART II — OTHER INFORMATION


ITEM 1 — LEGAL PROCEEDINGS

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

In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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

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


ITEM 1A — RISK FACTORS

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, ~~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.

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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 ended June 30, 2021, no~~The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the ~~Securities~~ Exchange Act for the quarter endedMarch 31, 2022:


	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2022 - Jan. 31, 2022	—	$	—	—	—
Feb. 1, 2022 - Feb. 28, 2022	—	—		—	—
March 1, 2022 - March 31, 2022 (a)	2,376	67.33		—	—
	2,376			—	—

(a)Xcel Energy Inc. or one of ~~1934 were purchased by or on behalf of us or any of our affiliated purchasers.~~

its agents periodically purchases common shares in open-market transactions in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.

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ITEM 6 — EXHIBITS

* Indicates incorporation by reference


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012	Xcel Energy Inc. Form 8-K dated May 16, 2012	3.01
3.02*	Bylaws of Xcel Energy Inc. as Amended on April 3, 2020	Xcel Energy Inc Form 8-K dated April 3, 2020	3.01


31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

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


		XCEL ENERGY INC.

~~July 29, 2021~~4/28/2022	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)

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(Millions of Dollars)	Limit		Amount Used		Available
Xcel Energy Inc.	$	1,200	$	1,200	$	0


(Millions of Dollars)	Three Months Ended June 30, 2021 vs. 2020		Six Months Ended June 30, 2021 vs. 2020
Non-fuel riders	$	89	$	133
Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota)	34		78

Proprietary commodity trading, net of sharing — Winter Storm Uri	—		27
Sales and demand (a)	24		10
Estimated impact of weather (net of decoupling/sales true-up)	(1)		5
Wholesale transmission revenue (net)	(8)		3
PTCs flowed back to customers (offset by lower ETR)	(42)		(79)
Other (net)	1		(2)
Total increase in electric margin	$	97	$	175