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, ~~2020~~ 2021


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

For the transition period from to

Commission File Number: 001-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

Minnesota

~~001-3034~~

41-0448030

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

(Commission File Number)

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

414 Nicollet Mall

Minneapolis

Minnesota

55401

(Address of ~~Principal Executive Offices)~~principal executive offices)

(Zip Code)


~~612~~(612)			330-5500
(Registrant’s ~~Telephone Number, Including Area Code)~~telephone number, including area code)


N/A
(Former ~~Name, Former Address~~name, former address and ~~Former Fiscal Year,~~former fiscal year, if ~~Changed Since Last Report)~~changed since last report)

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

Title of each class

Trading ~~Symbol~~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 ~~28, 2020~~22, 2021
Common Stock, $2.50 par value						~~525,342,304~~538,436,651 shares

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

Item 1 —

Financial Statements (unaudited)

Consolidated Statements of Income

Consolidated Statements of Comprehensive Income

Consolidated Statements of Cash Flows

Consolidated Balance Sheets

Consolidated Statements of Common Stockholders’ Equity

Notes to Consolidated Financial Statements

Item 2 —

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3 —

Quantitative and Qualitative Disclosures ~~about~~A bout Market Risk

3534

Item 4 —

Controls and Procedures

3534

PART II

OTHER INFORMATION

Item 1 —

Item 1A —

Item 2 —

Unregistered Sales of Equity Securities and Use of Proceeds

Item 6 —

~~Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~

~~Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available on various filings with the Securities and Exchange ~~Commission (SEC).~~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 System~~			~~The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota~~
NSP-Wisconsin			Northern States Power Company, a Wisconsin corporation
PSCo			Public Service Company of Colorado
SPS			Southwestern Public Service ~~Co.~~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			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 ~~the~~ 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
~~FPPCAC~~			~~Fuel and purchased power cost adjustment clause~~
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			FASB Accounting Standards Codification
C&I			Commercial and Industrial
CCR			Coal combustion ~~residual~~residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by ~~the~~ 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
COVID-19			Novel coronavirus
~~CWIP~~			~~Construction work in progress~~
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			~~Generally~~United States generally accepted accounting principles
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
~~ROFR~~			~~Right-of-first refusal~~
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
KV			~~Kilovolts~~
MW			Megawatts


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including ~~the 2020~~those relating to 2021 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future ~~bad debt expense, and~~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 on our results of operations, financial condition and cash flows or 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 ~~securities~~ filings with the SEC (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, ~~2019,~~2020, and subsequent ~~securities~~ filings), 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; operational safety, including our nuclear generation facilities; 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; 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 and their impact on capital expenditures and 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.

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 June 30				Six Months Ended June 30
		2020		2019		2020		2019			2021		2020		2021		2020
Operating revenues	Operating revenues									Operating revenues
Electric	Electric	$	2,286	$	2,249	$	4,489	$	4,574	Electric	$	2,597	$	2,286	$	5,467	$	4,489
Natural gas	Natural gas	280		308		863		1,102		Natural gas	449		280		1,096		863
Other	Other	20		20		45		42		Other	22		20		46		45
Total operating revenues	Total operating revenues	2,586		2,577		5,397		5,718		Total operating revenues	3,068		2,586		6,609		5,397

Operating expenses	Operating expenses									Operating expenses
Electric fuel and purchased power	Electric fuel and purchased power	833		813		1,630		1,727		Electric fuel and purchased power	1,047		833		2,433		1,630
Cost of natural gas sold and transported	Cost of natural gas sold and transported	86		112		371		591		Cost of natural gas sold and transported	218		86		517		371
Cost of sales — other	Cost of sales — other	8		10		17		19		Cost of sales — other	9		8		17		17
Operating and maintenance expenses	Operating and maintenance expenses	550		586		1,129		1,184		Operating and maintenance expenses	600		550		1,184		1,129
Conservation and demand side management expenses	Conservation and demand side management expenses	68		65		142		137		Conservation and demand side management expenses	71		68		144		142
Depreciation and amortization	Depreciation and amortization	473		439		936		872		Depreciation and amortization	528		473		1,049		936
Taxes (other than income taxes)	Taxes (other than income taxes)	146		142		295		292		Taxes (other than income taxes)	157		146		320		295
Total operating expenses	Total operating expenses	2,164		2,167		4,520		4,822		Total operating expenses	2,630		2,164		5,664		4,520

Operating income	Operating income	422		410		877		896		Operating income	438		422		945		877

Other income (expense), net	Other income (expense), net	5		2		(7)		6		Other income (expense), net	3		5		8		(7)
Equity earnings of unconsolidated subsidiaries		6		9		17		19
Earnings from equity method investments										Earnings from equity method investments	20		6		34		17
Allowance for funds used during construction — equity	Allowance for funds used during construction — equity	37		20		61		40		Allowance for funds used during construction — equity	18		37		32		61

Interest charges and financing costs	Interest charges and financing costs									Interest charges and financing costs
Interest charges — includes other financing costs of $7, $6, $14 and $13, respectively		208		189		407		379
Interest charges — includes other financing costs of $7, $7, $14 and $14, respectively										Interest charges — includes other financing costs of $7, $7, $14 and $14, respectively	212		208		417		407
Allowance for funds used during construction — debt	Allowance for funds used during construction — debt	(12)		(10)		(22)		(20)		Allowance for funds used during construction — debt	(6)		(12)		(11)		(22)
Total interest charges and financing costs	Total interest charges and financing costs	196		179		385		359		Total interest charges and financing costs	206		196		406		385

Income before income taxes	Income before income taxes	274		262		563		602		Income before income taxes	273		274		613		563
Income tax (benefit) expense		(13)		24		(19)		49
Income tax benefit										Income tax benefit	(38)		(13)		(60)		(19)
Net income	Net income	$	287	$	238	$	582	$	553	Net income	$	311	$	287	$	673	$	582

Weighted average common shares outstanding:	Weighted average common shares outstanding:									Weighted average common shares outstanding:
Basic	Basic	527		516		526		515		Basic	539		527		539		526
Diluted	Diluted	527		518		527		517		Diluted	539		527		539		527

Earnings per average common share:	Earnings per average common share:									Earnings per average common share:
Basic	Basic	$	0.54	$	0.46	$	1.10	$	1.07	Basic	$	0.58	$	0.54	$	1.25	$	1.10
Diluted	Diluted	0.54		0.46		1.10		1.07		Diluted	0.58		0.54		1.25		1.10

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 June 30				Six Months Ended June 30
		2020		2019		2020		2019			2021		2020		2021		2020
Net income	Net income	$	287	$	238	$	582	$	553	Net income	$	311	$	287	$	673	$	582
Other comprehensive income (loss)	Other comprehensive income (loss)									Other comprehensive income (loss)
Pension and retiree medical benefits:	Pension and retiree medical benefits:									Pension and retiree medical benefits:
Net pension and retiree medical gains arising during the period, net of tax of $—, $—, $— and $1, respectively		—		1		—		3
Reclassifications of loss to net income, net of tax of $1, $—, $1 and $—, respectively		2		—		3		1

Reclassifications of loss to net income, net of tax of $0, $1, $1 and $1, respectively										Reclassifications of loss to net income, net of tax of $0, $1, $1 and $1, respectively	1		2		1		3
Derivative instruments:	Derivative instruments:									Derivative instruments:
Net fair value decrease, net of tax of $—, $(3), $(3) and $(5), respectively		—		(10)		(10)		(17)
Reclassification of loss to net income, net of tax of $1, $—, $1 and $—, respectively		1		1		3		2

Net fair value increase (decrease), net of tax of $0, $0, $0 and $(3), respectively										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										Reclassification of losses to net income, net of tax of $0, $1, $1 and $1, respectively	2		1		5		3

Total other comprehensive income (loss)	Total other comprehensive income (loss)	3		(8)		(4)		(11)		Total other comprehensive income (loss)	3		3		6		(4)
Total comprehensive income	Total comprehensive income	$	290	$	230	$	578	$	542	Total comprehensive income	$	314	$	290	$	679	$	578

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							Six Months Ended June 30
		2020		2019			2021		2020
Operating activities	Operating activities					Operating activities
Net income	Net income	$	582	$	553	Net income	$	673	$	582
Adjustments to reconcile net income to cash provided by operating activities:	Adjustments to reconcile net income to cash provided by operating activities:					Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	942		881		Depreciation and amortization	1,043		942
Nuclear fuel amortization	Nuclear fuel amortization	65		58		Nuclear fuel amortization	56		65
Deferred income taxes	Deferred income taxes	—		47		Deferred income taxes	(67)		0
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(61)		(40)		Allowance for equity funds used during construction	(32)		(61)
Equity earnings of unconsolidated subsidiaries		(17)		(19)
Dividends from unconsolidated subsidiaries		21		20
Earnings from equity method investments						Earnings from equity method investments	(34)		(17)
Dividends from equity method investments						Dividends from equity method investments	21		21
Provision for bad debts	Provision for bad debts	26		17		Provision for bad debts	27		26
Share-based compensation expense	Share-based compensation expense	41		35		Share-based compensation expense	21		41
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	19		105		Accounts receivable	(63)		19
Accrued unbilled revenues	Accrued unbilled revenues	97		115		Accrued unbilled revenues	14		97
Inventories	Inventories	15		25		Inventories	7		15
Other current assets	Other current assets	7		19		Other current assets	24		7
Accounts payable	Accounts payable	(160)		(157)		Accounts payable	(15)		(160)
Net regulatory assets and liabilities	Net regulatory assets and liabilities	12		25		Net regulatory assets and liabilities	(794)		12
Other current liabilities	Other current liabilities	(241)		(195)		Other current liabilities	(265)		(241)
Pension and other employee benefit obligations	Pension and other employee benefit obligations	(146)		(139)		Pension and other employee benefit obligations	(128)		(146)
Other, net	Other, net	(54)		(16)		Other, net	1		(54)
Net cash provided by operating activities	Net cash provided by operating activities	1,148		1,334		Net cash provided by operating activities	489		1,148

Investing activities	Investing activities					Investing activities
Capital/construction expenditures	Capital/construction expenditures	(2,569)		(1,689)		Capital/construction expenditures	(1,967)		(2,569)
Purchases of investment securities		(1,160)		(488)
Purchase of investment securities						Purchase of investment securities	(628)		(1,160)
Proceeds from the sale of investment securities	Proceeds from the sale of investment securities	1,150		478		Proceeds from the sale of investment securities	410		1,150
Other, net	Other, net	(1)		(9)		Other, net	(17)		(1)
Net cash used in investing activities	Net cash used in investing activities	(2,580)		(1,708)		Net cash used in investing activities	(2,202)		(2,580)

Financing activities	Financing activities					Financing activities
Proceeds from short-term borrowings, net	Proceeds from short-term borrowings, net	815		559		Proceeds from short-term borrowings, net	1,161		815
Proceeds from issuances of long-term debt	Proceeds from issuances of long-term debt	2,447		819		Proceeds from issuances of long-term debt	1,821		2,447
Repayments of long-term debt, including reacquisition premiums	Repayments of long-term debt, including reacquisition premiums	—		(400)		Repayments of long-term debt, including reacquisition premiums	(399)		0

Dividends paid	Dividends paid	(421)		(387)		Dividends paid	(460)		(421)
Other, net	Other, net	(23)		(11)		Other, net	(1)		(23)
Net cash provided by financing activities	Net cash provided by financing activities	2,818		580		Net cash provided by financing activities	2,122		2,818

Net change in cash, cash equivalents and restricted cash	Net change in cash, cash equivalents and restricted cash	1,386		206		Net change in cash, cash equivalents and restricted cash	409		1,386
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	248		147		Cash, cash equivalents and restricted cash at beginning of period	129		248
Cash, cash equivalents and restricted cash at end of period ^(a)	Cash, cash equivalents and restricted cash at end of period ^(a)	$	1,634	$	353	Cash, cash equivalents and restricted cash at end of period (a)	$	538	$	1,634

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)	$	(364)	$	(344)	Cash paid for interest (net of amounts capitalized)	$	(390)	$	(364)
Cash (paid) received for income taxes, net		(10)		54
Cash paid for income taxes, net						Cash paid for income taxes, net	(5)		(10)

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	$	436	$	304	Accrued property, plant and equipment additions	$	509	$	436
Inventory transfers to property, plant and equipment	Inventory transfers to property, plant and equipment	194		40		Inventory transfers to property, plant and equipment	43		194
Operating lease right-of-use assets	Operating lease right-of-use assets	8		1,843		Operating lease right-of-use assets	1		8
Allowance for equity funds used during construction	Allowance for equity funds used during construction	61		40		Allowance for equity funds used during construction	32		61
Issuance of common stock for equity awards	Issuance of common stock for equity awards	35		32		Issuance of common stock for equity awards	35		35

^(a) As of June 30, 2020, $9 million of cash was recorded in Prepayments and other current assets related to MEC.	^(a) As of June 30, 2020, $9 million of cash was recorded in Prepayments and other current assets related to MEC.					(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, 2020		Dec. 31, 2019			June 30, 2021		Dec. 31, 2020
Assets	Assets					Assets
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	1,625	$	248	Cash and cash equivalents	$	538	$	129
Accounts receivable, net	Accounts receivable, net	799		837		Accounts receivable, net	948		916
Accrued unbilled revenues	Accrued unbilled revenues	613		713		Accrued unbilled revenues	699		714
Inventories	Inventories	487		544		Inventories	500		535
Regulatory assets	Regulatory assets	513		488		Regulatory assets	1,041		640
Derivative instruments	Derivative instruments	72		55		Derivative instruments	148		49
Prepaid taxes	Prepaid taxes	73		43		Prepaid taxes	52		42
Prepayments and other	Prepayments and other	208		185		Prepayments and other	221		250
Total current assets	Total current assets	4,390		3,113		Total current assets	4,147		3,275

Property, plant and equipment, net	Property, plant and equipment, net	41,124		39,483		Property, plant and equipment, net	44,141		42,950

Other assets	Other assets					Other assets
Nuclear decommissioning fund and other investments	Nuclear decommissioning fund and other investments	2,683		2,731		Nuclear decommissioning fund and other investments	3,389		3,096
Regulatory assets	Regulatory assets	2,973		2,935		Regulatory assets	3,225		2,737
Derivative instruments	Derivative instruments	38		22		Derivative instruments	92		30
Operating lease right-of-use assets	Operating lease right-of-use assets	1,229		1,672		Operating lease right-of-use assets	1,390		1,490
Other	Other	1,019		492		Other	395		379
Total other assets	Total other assets	7,942		7,852		Total other assets	8,491		7,732
Total assets	Total assets	$	53,456	$	50,448	Total assets	$	56,779	$	53,957

Liabilities and Equity	Liabilities and Equity					Liabilities and Equity
Current liabilities	Current liabilities					Current liabilities
Current portion of long-term debt	Current portion of long-term debt	$	1,101	$	702	Current portion of long-term debt	$	21	$	421
Short-term debt	Short-term debt	1,410		595		Short-term debt	1,745		584
Accounts payable	Accounts payable	1,188		1,294		Accounts payable	1,273		1,237
Regulatory liabilities	Regulatory liabilities	420		407		Regulatory liabilities	336		311
Taxes accrued	Taxes accrued	343		466		Taxes accrued	428		578
Accrued interest	Accrued interest	200		192		Accrued interest	207		203
Dividends payable	Dividends payable	226		212		Dividends payable	246		231
Derivative instruments	Derivative instruments	40		38		Derivative instruments	65		53
Operating lease liabilities	Operating lease liabilities	149		194		Operating lease liabilities	220		214
Other	Other	396		468		Other	409		407
Total current liabilities	Total current liabilities	5,473		4,568		Total current liabilities	4,950		4,239

Deferred credits and other liabilities	Deferred credits and other liabilities					Deferred credits and other liabilities
Deferred income taxes	Deferred income taxes	4,569		4,509		Deferred income taxes	4,807		4,746
Deferred investment tax credits		47		49

Regulatory liabilities	Regulatory liabilities	5,310		5,077		Regulatory liabilities	5,387		5,302
Asset retirement obligations	Asset retirement obligations	2,881		2,701		Asset retirement obligations	3,059		2,884
Derivative instruments	Derivative instruments	181		175		Derivative instruments	147		131
Customer advances	Customer advances	201		203		Customer advances	196		197
Pension and employee benefit obligations	Pension and employee benefit obligations	636		785		Pension and employee benefit obligations	521		666
Operating lease liabilities	Operating lease liabilities	1,125		1,549		Operating lease liabilities	1,236		1,344
Other	Other	185		186		Other	208		228
Total deferred credits and other liabilities	Total deferred credits and other liabilities	15,135		15,234		Total deferred credits and other liabilities	15,561		15,498

Commitments and contingencies	Commitments and contingencies					Commitments and contingencies	0		0
Capitalization	Capitalization					Capitalization
Long-term debt	Long-term debt	19,463		17,407		Long-term debt	21,476		19,645
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 525,204,978 and 524,539,000 shares outstanding at June 30, 2020 and Dec. 31, 2019, respectively		1,313		1,311
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						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	Additional paid in capital	6,679		6,656		Additional paid in capital	7,435		7,404
Retained earnings	Retained earnings	5,538		5,413		Retained earnings	6,146		5,968
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(145)		(141)		Accumulated other comprehensive loss	(135)		(141)
Total common stockholders’ equity	Total common stockholders’ equity	13,385		13,239		Total common stockholders’ equity	14,792		14,575
Total liabilities and equity	Total liabilities and equity	$	53,456	$	50,448	Total liabilities and equity	$	56,779	$	53,957

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

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)

(amounts in millions, except per share data; shares in ~~thousands)~~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											Total Common Stockholders’ Equity				Shares			Par Value			Additional Paid In Capital			Retained Earnings				Accumulated Other Comprehensive Loss			Total Common Stockholders' Equity
Three Months Ended June 30, 2020 and 2019
Balance at March 31, 2019		514,668	$	1,287	$	6,173	$	4,996	$	(127)	$	12,329
Net income							238				238
Other comprehensive loss									(8)		(8)
Dividends declared on common stock ($0.41 per share)							(209)				(209)
Issuances of common stock		197	—		10						10

Share-based compensation					7		(1)				6
Balance at June 30, 2019		514,865	$	1,287	$	6,190	$	5,024	$	(135)	$	12,366

Three Months Ended June 30, 2021 and 2020													Three Months Ended June 30, 2021 and 2020
Balance at March 31, 2020	Balance at March 31, 2020	525,034	$	1,313	$	6,659	$	5,478	$	(148)	$	13,302	Balance at March 31, 2020	525,033,594			$	1,313			$	6,659		$	5,478		$	(148)			$	13,302
Net income	Net income						287				287		Net income											287							287
Other comprehensive income	Other comprehensive income								3		3		Other comprehensive income														3				3
Dividends declared on common stock ($0.43 per share)	Dividends declared on common stock ($0.43 per share)						(226)				(226)		Dividends declared on common stock ($0.43 per share)											(226)							(226)
Issuances of common stock	Issuances of common stock	171	—		11						11		Issuances of common stock	171,384			0				11										11

Share-based compensation	Share-based compensation				9		(1)				8		Share-based compensation								9			(1)							8
Balance at June 30, 2020	Balance at June 30, 2020	525,205	$	1,313	$	6,679	$	5,538	$	(145)	$	13,385	Balance at June 30, 2020	525,204,978			$	1,313			$	6,679		$	5,538		$	(145)			$	13,385

Balance at March 31, 2021													Balance at March 31, 2021	538,076,662			$	1,345			$	7,411		$	6,082		$	(138)			$	14,700
Net income													Net income											311							311
Other comprehensive income													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)
Issuances of common stock													Issuances of common stock	229,265			1				14										15

Share-based compensation													Share-based compensation								10			(1)							9
Balance at June 30, 2021													Balance at June 30, 2021	538,305,927			$	1,346			$	7,435		$	6,146		$	(135)			$	14,792
		Common Stock Issued									Retained Earnings				Accumulated Other Comprehensive Loss				Total Common Stockholders’ Equity
		Shares	Par Value		Additional Paid In Capital											Total Common Stockholders’ Equity		Common Stock Issued									Retained Earnings				Accumulated Other Comprehensive Loss				Total Common Stockholders' Equity
Six Months Ended June 30, 2020 and 2019
Balance at Dec. 31, 2018		514,037	$	1,285	$	6,168	$	4,893	$	(124)	$	12,222
Net income							553				553
Other comprehensive loss									(11)		(11)
Dividends declared on common stock ($0.81 per share)							(419)				(419)
Issuances of common stock		834	2		20						22
Repurchases of common stock		(6)	—		—						—
Share-based compensation					2		(3)				(1)
Balance at June 30, 2019		514,865	$	1,287	$	6,190	$	5,024	$	(135)	$	12,366
														Shares				Par Value					Additional Paid In Capital			Retained Earnings					Accumulated Other Comprehensive Loss				Total Common Stockholders' Equity
Six Months Ended June 30, 2021 and 2020													Six Months Ended June 30, 2021 and 2020
Balance at Dec. 31, 2019	Balance at Dec. 31, 2019	524,539	$	1,311	$	6,656	$	5,413	$	(141)	$	13,239	Balance at Dec. 31, 2019	524,539,000			$	1,311			$	6,656		$	5,413				$	(141)			$	13,239
Net income	Net income						582				582		Net income											582							582
Other comprehensive loss	Other comprehensive loss								(4)		(4)		Other comprehensive loss														(4)				(4)
Dividends declared on common stock ($0.86 per share)	Dividends declared on common stock ($0.86 per share)						(453)				(453)		Dividends declared on common stock ($0.86 per share)											(453)							(453)
Issuances of common stock	Issuances of common stock	666	2		21						23		Issuances of common stock	665,978			2				21										23

Share-based compensation	Share-based compensation				2		(2)				—		Share-based compensation								2			(2)							0
Adoption of ASC Topic 326	Adoption of ASC Topic 326						(2)				(2)		Adoption of ASC Topic 326											(2)							(2)
Balance at June 30, 2020	Balance at June 30, 2020	525,205	$	1,313	$	6,679	$	5,538	$	(145)	$	13,385	Balance at June 30, 2020	525,204,978			$	1,313			$	6,679		$	5,538		$	(145)			$	13,385

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											673							673
Other comprehensive income													Other comprehensive income														6				6
Dividends declared on common stock ($0.915 per share)													Dividends declared on common stock ($0.915 per share)											(492)							(492)
Issuances of common stock													Issuances of common stock	867,533			2				28										30

Share-based compensation													Share-based compensation								3			(3)							0
Balance at June 30, 2021													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

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 ~~U.S.~~ GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of June 30, ~~2020~~2021 and Dec. 31, ~~2019;~~2020; the results of ~~its~~Xcel Energy’s operations, including the components of net income, ~~and~~ comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, ~~2020~~2021 and ~~2019;~~2020, and its cash flows for the six months ended June 30, ~~2020~~2021 and ~~2019.~~2020.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, ~~2020,~~2021, 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, ~~2019,~~2020 balance sheet information has been derived from the audited ~~2019~~2020 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2019.~~2020.

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, ~~2019,~~2020, filed with the SEC on Feb. ~~21, 2020.~~ 17, 2021.

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, ~~2019,~~2020 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

~~Recently Adopted~~

Credit Losses — In 2016, 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 ~~doubtful accounts~~bad debts on accrued unbilled revenues, the Jan. 1, 2020, adoption of ASC Topic 326 did not have a significant impact on Xcel Energy’s consolidated financial statements.


3. Selected Balance Sheet Data


(Millions of Dollars)	(Millions of Dollars)	June 30, 2020		Dec. 31, 2019		(Millions of Dollars)	June 30, 2021		Dec. 31, 2020
Accounts receivable, net	Accounts receivable, net					Accounts receivable, net
Accounts receivable	Accounts receivable	$	859	$	892	Accounts receivable	$	1,039	$	995
Less allowance for bad debts	Less allowance for bad debts	(60)		(55)		Less allowance for bad debts	(91)		(79)
Accounts receivable, net	Accounts receivable, net	$	799	$	837	Accounts receivable, net	$	948	$	916


(Millions of Dollars)	(Millions of Dollars)	June 30, 2020		Dec. 31, 2019		(Millions of Dollars)	June 30, 2021		Dec. 31, 2020
Inventories	Inventories					Inventories
Materials and supplies	Materials and supplies	$	277	$	270	Materials and supplies	$	281	$	275
Fuel	Fuel	173		191		Fuel	166		176
Natural gas	Natural gas	37		83		Natural gas	53		84
Total inventories	Total inventories	$	487	$	544	Total inventories	$	500	$	535


(Millions of Dollars)	(Millions of Dollars)	June 30, 2020		Dec. 31, 2019		(Millions of Dollars)	June 30, 2021		Dec. 31, 2020
Property, plant and equipment, net	Property, plant and equipment, net					Property, plant and equipment, net
Electric plant	Electric plant	$	45,413	$	44,355	Electric plant	$	48,861	$	47,104
Natural gas plant	Natural gas plant	6,747		6,560		Natural gas plant	7,315		7,135
Common and other property	Common and other property	2,385		2,341		Common and other property	2,524		2,503
Plant to be retired ^(a)	Plant to be retired ^(a)	292		259		Plant to be retired (a)	630		677
CWIP		3,060		2,329
Construction work in progress						Construction work in progress	1,851		1,877
Total property, plant and equipment	Total property, plant and equipment	57,897		55,844		Total property, plant and equipment	61,181		59,296
Less accumulated depreciation	Less accumulated depreciation	(17,097)		(16,735)		Less accumulated depreciation	(17,382)		(16,657)
Nuclear fuel	Nuclear fuel	2,925		2,909		Nuclear fuel	3,057		2,970
Less accumulated amortization	Less accumulated amortization	(2,601)		(2,535)		Less accumulated amortization	(2,715)		(2,659)
Property, plant and equipment, net	Property, plant and equipment, net	$	41,124	$	39,483	Property, plant and equipment, net	$	44,141	$	42,950

^(a)~~In 2018, the CPUC approved early retirement~~Includes regulator-approved retirements of ~~PSCo’s~~ Comanche Units 1 and 2 ~~in approximately 2022~~ and ~~2025, respectively. PSCo also expects~~jointly owned Craig Unit 1 for PSCo and Sherco Units 1 and 2 for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to ~~be retired early in 2025. Amounts are presented net~~natural gas, and PSCo’s planned retirement of ~~accumulated depreciation.~~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 were as follows:~~Energy:


(Amounts in Millions, Except Interest Rates)	(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2020			Year Ended Dec. 31, 2019			(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2021			Year Ended Dec. 31, 2020
Borrowing limit	Borrowing limit	$	4,300		$	3,600		Borrowing limit	$	4,300		$	3,100
Amount outstanding at period end	Amount outstanding at period end	1,410			595			Amount outstanding at period end	1,745			584
Average amount outstanding	Average amount outstanding	1,496			1,115			Average amount outstanding	1,521			1,126
Maximum amount outstanding	Maximum amount outstanding	1,770			1,780			Maximum amount outstanding	1,745			2,080
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	1.65		%	2.72		%	Weighted average interest rate, computed on a daily basis	0.66		%	1.45		%
Weighted average interest rate at period end	Weighted average interest rate at period end	0.76			2.34			Weighted average interest rate at period end	0.58			0.23

Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain ~~operating~~ obligations. At both June 30, ~~2020~~2021 and Dec. 31, ~~2019,~~2020, there were $20 million of letters of credit outstanding under the credit facilities. ~~The contract amounts of these letters of credit~~Amounts approximate their fair value and are subject to fees.

Table of Contents

Revolving Credit Facilities — In order to ~~use~~issue commercial paper, ~~programs to fulfill short-term funding needs,~~ Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities ~~in place~~ at least equal to the amount of ~~their respective~~ commercial paper borrowing limits and cannot issue commercial paper ~~in an aggregate amount~~ exceeding available ~~capacity under these~~ credit ~~facilities.~~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, ~~2020,~~2021, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	(Millions of Dollars)	Credit Facility ^(a)		Outstanding ^(b)		Available		(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	Xcel Energy Inc.	$	1,250	$	210	$	1,040	Xcel Energy Inc.	$	1,250	$	545	$	705
PSCo	PSCo	700		8		692		PSCo	700		8		692
NSP-Minnesota	NSP-Minnesota	500		2		498		NSP-Minnesota	500		9		491
SPS	SPS	500		10		490		SPS	500		2		498
NSP-Wisconsin	NSP-Wisconsin	150		—		150		NSP-Wisconsin	150		0		150
Total	Total	$	3,100	$	230	$	2,870	Total	$	3,100	$	564	$	2,536

^(a)Expires in June 2024.

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

Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the ~~revolving~~ credit facility termination date for two additional one-year periods. 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.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available ~~capacity under the respective~~ credit ~~facilities.~~facilities capacity. Xcel Energy Inc. and its utility subsidiaries had 0 direct advances on the credit facilities outstanding as of June 30, ~~2020~~2021 and Dec. 31, ~~2019.~~2020.

Term Loan Agreements — In ~~December 2019,~~February 2021, Xcel Energy Inc. entered into a ~~$500 million~~$1.2 billion 364-Day Term Loan Agreement that matures ~~Dec. 1, 2020.~~Feb. 17, 2022. Xcel Energy has an option to ~~request an extension~~extend through Nov. 30, 2021. In March 2020, Xcel Energy Inc. entered into a $700 million, 364-Day Term Loan Agreement. The loan is unsecured and matures March 22, 2021. Xcel Energy has an option to request an extension through March 21, 2022.Feb. 16, 2023. The term ~~loans include~~loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to ~~65 percent. Interest is at a rate equal to either the Eurodollar rate, plus 60.0 basis points, or an alternate base rate.~~65%.

As of June 30, ~~2020,~~2021, Xcel Energy Inc.’s term loan borrowings were as follows:


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

Bilateral Credit Agreement

In ~~March 2019, NSP-Minnesota entered into a one year~~April 2021, the uncommitted bilateral credit ~~agreement.~~agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. ~~In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one year term.~~

As of June 30, ~~2020,~~2021, NSP-Minnesota’s outstanding letters of credit under the 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	$	31	$	44	NSP-Minnesota	$	75	$	75	$	0

Long-Term Borrowings and Other Financing Instruments

During the six months ended June 30, ~~2020,~~2021, Xcel Energy Inc. and its utility subsidiaries issued the following:

•~~Xcel Energy Inc.~~ PSCoissued ~~$600~~$750 million of ~~3.40% senior unsecured notes due June 1, 2030;~~

•~~PSCo issued $375 million of 2.70%~~1.875% first mortgage bonds due ~~Jan.~~June 15, ~~2051 and $375 million of 1.90% first mortgage bonds due Jan. 15, 2031;~~2031.

•SPS issued ~~$350~~$250 million of 3.15% first mortgage bonds due ~~May 1, 2050;~~

•~~NSP-Wisconsin issued $100 million of 3.05% first mortgage bonds due May 1, 2051; and~~2050.

•NSP-Minnesota issued ~~$700~~$425 million of ~~2.60%~~2.25% first mortgage bonds due ~~June~~April 1, ~~2051.~~

~~Forward Equity Agreements~~ —In November 2019, Xcel Energy Inc. entered into forward sale agreements in connection with a completed $743 million public offering of 11.8 million shares of Xcel Energy common stock. The initial forward agreement was for 10.3 million shares with an additional agreement for 1.5 million shares that was exercised at the option of the banking counterparty.

At June 30, 2020, the forward agreements could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $728 million. The forward instruments could also have been settled at June 30, 2020, with delivery of approximately $242031 and $425 million of ~~cash or approximately 0.4 million shares of common stock to the counterparty, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.~~

~~The forward price used to determine amounts~~3.20% first mortgage bonds due at settlement is calculated based on the November 2019 public offering price for Xcel Energy’s common stock of $62.69, increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the instruments are outstanding.

~~Xcel Energy may settle the agreements at any time up to the maturity date of Dec. 31, 2020. Depending on settlement timing, cash proceeds are expected to be approximately $720 million to $730 million.~~

~~Forward equity instruments were recognized within stockholders’ equity at fair value at execution of the agreements and will not be subsequently adjusted until settlement.~~April 1, 2052.

Other Equity — Xcel Energy Inc. issued $28 million and $20 million ~~and $19 million~~of equity through the DRIP during the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively. The program allows shareholders to ~~elect dividend reinvestment~~reinvest their dividends in Xcel Energy Inc. common stock through a non-cash transaction.

~~Table of Contents~~


5. Revenues

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


		Three Months Ended June 30, 2020															Three Months Ended June 30, 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	$	718	$	167	$	10	$	895	Residential	$	756	$	257	$	11	$	1,024
C&I	C&I	1,075		73		6		1,154		C&I	1,282		126		6		1,414
Other	Other	31		—		1		32		Other	32		0		2		34
Total retail	Total retail	1,824		240		17		2,081		Total retail	2,070		383		19		2,472
Wholesale	Wholesale	160		—		—		160		Wholesale	234		0		0		234
Transmission	Transmission	153		—		—		153		Transmission	148		0		0		148
Other	Other	21		26		—		47		Other	20		42		0		62
Total revenue from contracts with customers	Total revenue from contracts with customers	2,158		266		17		2,441		Total revenue from contracts with customers	2,472		425		19		2,916
Alternative revenue and other	Alternative revenue and other	128		14		3		145		Alternative revenue and other	125		24		3		152
Total revenues	Total revenues	$	2,286	$	280	$	20	$	2,586	Total revenues	$	2,597	$	449	$	22	$	3,068

Three Months Ended June 30, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 624 $ 182 $ 10 $ 816
C&I 1,201 90 6 1,297
Other 31 — 1 32
Total retail 1,856 272 17 2,145
Wholesale 154 — — 154
Transmission 127 — — 127
Other 11 26 — 37
Total revenue from contracts with customers 2,148 298 17 2,463
Alternative revenue and other 101 10 3 114
Total revenues $ 2,249 $ 308 $ 20 $ 2,577

Six Months Ended June 30, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,394 $ 522 $ 21 $ 1,937
C&I 2,141 253 15 2,409
Other 60 — 2 62
Total retail 3,595 775 38 4,408
Wholesale 326 — — 326
Transmission 285 — — 285
Other 38 58 — 96
Total revenue from contracts with customers 4,244 833 38 5,115
Alternative revenue and other 245 30 7 282
Total revenues $ 4,489 $ 863 $ 45 $ 5,397


		Six Months Ended June 30, 2019															Three Months Ended June 30, 2020
(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	$	1,351	$	677	$	19	$	2,047	Residential	$	718	$	167	$	10	$	895
C&I	C&I	2,341		345		15		2,701		C&I	1,075		73		6		1,154
Other	Other	63		—		2		65		Other	31		0		1		32
Total retail	Total retail	3,755		1,022		36		4,813		Total retail	1,824		240		17		2,081
Wholesale	Wholesale	343		—		—		343		Wholesale	160		0		0		160
Transmission	Transmission	258		—		—		258		Transmission	153		0		0		153
Other	Other	29		60		—		89		Other	21		26		0		47
Total revenue from contracts with customers	Total revenue from contracts with customers	4,385		1,082		36		5,503		Total revenue from contracts with customers	2,158		266		17		2,441
Alternative revenue and other	Alternative revenue and other	189		20		6		215		Alternative revenue and other	128		14		3		145
Total revenues	Total revenues	$	4,574	$	1,102	$	42	$	5,718	Total revenues	$	2,286	$	280	$	20	$	2,586

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	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
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,394	$	522	$	21	$	1,937
C&I	2,141		253		15		2,409
Other	60		0		2		62
Total retail	3,595		775		38		4,408
Wholesale	326		0		0		326
Transmission	285		0		0		285
Other	38		58		0		96
Total revenue from contracts with customers	4,244		833		38		5,115
Alternative revenue and other	245		30		7		282
Total revenues	$	4,489	$	863	$	45	$	5,397


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, ~~2019,~~2020 represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated ~~herein~~ by reference.

~~The following table reconciles the difference~~Difference between the statutory rate and ~~the~~ ETR:


		Three Months Ended June 30						Six Months Ended June 30							Three Months Ended June 30				Six Months Ended June 30
		2020		2019		2020		2019			2021		2020		2021		2020
Federal statutory rate	Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	State tax (net of federal tax effect)	5.1		5.0		5.0		5.0		State tax (net of federal tax effect)	4.9		5.1		4.9		5.0
Decreases in tax from:
Decreases:										Decreases:
Wind PTCs	Wind PTCs	(21.1)		(11.9)		(19.1)		(10.0)		Wind PTCs	(33.1)		(21.1)		(28.4)		(19.1)
Plant regulatory differences ^(a)	Plant regulatory differences ^(a)	(7.1)		(5.5)		(7.8)		(5.6)		Plant regulatory differences (a)	(6.6)		(7.1)		(6.3)		(7.8)
Other tax credits, net NOL & tax credit allowances		(1.9)		(0.6)		(1.4)		(1.8)
Other (net)	Other (net)	(0.7)		1.2		(1.1)		(0.5)		Other (net)	(0.1)		(2.6)		(1.0)		(2.5)
Effective income tax rate	Effective income tax rate	(4.7)	%	9.2	%	(3.4)	%	8.1	%	Effective income tax rate	(13.9)	%	(4.7)	%	(9.8)	%	(3.4)	%

^(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
~~2009~~ — ~~2013~~						~~September 2020~~
2014 — 2016						~~June~~January 2022
2017						September 2021

~~In 2017,~~Additionally, the ~~IRS concluded the audit~~statute of limitations related to a federal tax ~~years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR.~~loss carryback claim filed in 2020 has been extended. Xcel Energy ~~filed~~has recognized its best estimate of income tax expense that will result from a ~~protest with~~final resolution of this issue; however, the ~~IRS. In April 2020, Xcel Energy~~outcome and ~~Appeals reached an agreement and no material adjustments were required.~~

~~In 2018, the IRS began an audit~~timing of ~~tax years 2014 - 2016. As of June 30, 2020, no adjustments have been proposed.~~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.

~~Table of Contents~~

As of June 30, ~~2020,~~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						~~2009~~2013
Texas						~~2009~~2012
Wisconsin						~~2014~~2016

•In ~~2018, Wisconsin~~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 2014 - 2016. As of June 30, 2020, 0~~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, ~~2020.~~2021.

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

Unrecognized tax benefits — permanent vs. temporary:


(Millions of Dollars)	(Millions of Dollars)	June 30, 2020		Dec. 31, 2019		(Millions of Dollars)	June 30, 2021		Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions	Unrecognized tax benefit — Permanent tax positions	$	36	$	35	Unrecognized tax benefit — Permanent tax positions	$	43	$	41��
Unrecognized tax benefit — Temporary tax positions	Unrecognized tax benefit — Temporary tax positions	10		9		Unrecognized tax benefit — Temporary tax positions	11		11
Total unrecognized tax benefit	Total unrecognized tax benefit	$	46	$	44	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, 2020 Dec. 31, 2019
NOL and tax credit carryforwards $ (41) $ (40)

~~Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $31 million at June 30, 2020 and $29 million at Dec. 31, 2019.~~


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

As ~~the~~ IRS audits resume and the state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$23~~$28 million in the next 12 months.

~~Payables~~Payable for interest related to unrecognized tax benefits ~~were not material~~is partially offset by the interest benefit associated with NOL and ~~0 amounts~~tax credit carryforwards.

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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 ~~for penalties~~ related to unrecognized tax benefits as of June 30, ~~2020~~2021 or Dec. 31, ~~2019.~~2020.


7. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted ~~average~~ 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 ~~forward equity agreements and~~ time-based equity compensation awards.

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

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

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

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

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


	Three Months Ended June 30		Six Months Ended June 30
(Shares in Millions)	2021	2020	2021	2020
Basic	539	527	539	526
Diluted (a)	539	527	539	527

(a) Diluted common shares outstanding included common stock equivalents of 0.3 million and 0.5 million for the three months ended June 30, 2021 and 2020, respectively. Diluted common shares outstanding included common stock equivalents of 0.3 million and 0.7 million for the ~~three and~~ six months ended June 30, 2021 and 2020, ~~respectively, and 1.8 million and 1.5 million for the three and six months ended June 30, 2019,~~ 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;~~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; and~~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~~funds’ investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

~~Table of Contents~~

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

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

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable ~~forecasts of forward prices and volatilities~~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.

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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 ~~included in~~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 ~~insignificant~~immaterial to the consolidated financial statements.

Non-Derivative Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved 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 ~~$637 million~~$1.2 billion and ~~$706~~$981 million as of June 30, ~~2020~~2021 and Dec. 31, ~~2019,~~2020, respectively, and unrealized losses were ~~$16~~$3 million and $6$5 million as of June 30, ~~2020~~2021 and Dec. 31, ~~2019,~~2020, respectively.

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


		June 30, 2020																							June 30, 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	$	22	$	22	$	—	$	—	$	—	$	22	Cash equivalents	$	30	$	30	$	0	$	0	$	0	$	30
Commingled funds	Commingled funds	766		—		—		—		897		897		Commingled funds	800		0		0		0		1,164		1,164
Debt securities	Debt securities	513		—		531		10		—		541		Debt securities	612		0		641		16		0		657
Equity securities	Equity securities	473		934		1		—		—		935		Equity securities	408		1,185		2		0		0		1,187
Total	Total	$	1,774	$	956	$	532	$	10	$	897	$	2,395	Total	$	1,850	$	1,215	$	643	$	16	$	1,164	$	3,038

^(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance ~~sheet,~~sheets, which also includes ~~$155~~$189 million of equity method investments ~~in unconsolidated subsidiaries~~ and ~~$133~~$162 million of rabbi trust assets and miscellaneous investments.

Dec. 31, 2019
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund ^(a)
Cash equivalents $ 33 $ 33 $ — $ — $ — $ 33
Commingled funds 733 — — — 935 935
Debt securities 489 — 495 13 — 508
Equity securities 485 962 2 — — 964
Total $ 1,740 $ 995 $ 497 $ 13 $ 935 $ 2,440


	Dec. 31, 2020
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	40	$	40	$	0	$	0	$	0	$	40
Commingled funds	787		0		0		0		1,041		1,041
Debt securities	528		0		572		13		0		585
Equity securities	446		1,109		2		0		0		1,111
Total	$	1,801	$	1,149	$	574	$	13	$	1,041	$	2,777

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance ~~sheet,~~sheets, which also includes ~~$155~~$165 million of equity method investments ~~in unconsolidated subsidiaries~~ and ~~$136~~$154 million of rabbi trust assets and other miscellaneous investments.

For the three and six months ended June 30, ~~2020~~2021 and ~~2019,~~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, ~~2020:~~2021:


		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	$	(4)	$	98	$	212	$	235	$	541	Debt securities	$	2	$	153	$	210	$	292	$	657

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.

~~Table of Contents~~

Cost and fair value of assets held in rabbi trusts:


		June 30, 2020																			June 30, 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	$	17	$	17	$	—	$	—	$	17	Cash equivalents	$	23	$	23	$	0	$	0	$	23
Mutual funds	Mutual funds	57		61		—		—		61		Mutual funds	71		84		0		0		84
Total	Total	$	74	$	78	$	—	$	—	$	78	Total	$	94	$	107	$	0	$	0	$	107


		Dec. 31, 2019																			Dec. 31, 2020
				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	$	17	$	17	$	—	$	—	$	17	Cash equivalents	$	32	$	32	$	0	$	0	$	32
Mutual funds	Mutual funds	57		65		—		—		65		Mutual funds	60		70		0		0		70
Total	Total	$	74	$	82	$	—	$	—	$	82	Total	$	92	$	102	$	0	$	0	$	102

^(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance ~~sheet.~~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, ~~2020,~~2021, accumulated other comprehensive loss related to settled interest rate derivatives included $5$6 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, ~~2020.~~2021, Xcel Energy had 0 unsettled interest rate derivatives.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.

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

Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. ~~Changes in the fair value~~The classification of ~~non-trading commodity derivative~~gains or losses for these instruments ~~are recorded as other comprehensive income or deferred~~ as a regulatory asset or ~~liability. The classification as a regulatory asset or~~ liability, if applicable, is based on approved regulatory recovery mechanisms.

As of June 30, ~~2020,~~2021, Xcel Energy had 0 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, 2020

Dec. 31, 2019

(Amounts in Millions) (a)(b)

June 30, 2021

Dec. 31, 2020

Megawatt hours of electricity

127

Megawatt hours of electricity

122

Million British thermal units of natural gas

153

110

Million British thermal units of natural gas

169

175

^(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, ~~2020,~~2021, 6 of Xcel Energy’s 10 most significant counterparties for these activities, comprising ~~$152~~$118 million, or ~~57%~~44%, 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 ~~$36~~$27 million, or ~~14%~~10%, 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 ~~$13~~$62 million or 5%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.

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)

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~~Impact of derivative activity:~~


	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Three Months Ended June 30, 2021
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	0		$	0
Total	$	2		$	0		$	0
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
Commodity trading	$	0		$	0		$	48	(b)
Electric commodity	0			(23)		(c)	0
Natural gas commodity	0			8		(d)	(10)		(d)
Total	$	0		$	(15)		$	38

Three Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	0		$	0
Total	$	2		$	0		$	0
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
Commodity trading	$	0		$	0		$	(5)	(b)
Electric commodity	0			(7)		(c)	0
Natural gas commodity	0			5		(d)	(6)		(d)
Total	$	0		$	(2)		$	(11)


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:(a)
~~(Millions of Dollars)~~	Accumulated Other Comprehensive Loss		Regulatory (Assets) and Liabilities
~~Three Months Ended June 30, 2020~~



~~Other derivative instruments~~

~~Natural gas commodity~~	$	—	$	~~(3)~~
~~Total~~	$	—	$	~~(3)~~

~~Six Months Ended June 30, 2020~~
~~Derivatives designated as cash flow hedges~~
~~Interest rate~~	$	~~(13)~~	$	—
~~Total~~	$	~~(13)~~	$	—
~~Other derivative instruments~~

~~Natural gas commodity~~	$	—	$	~~(3)~~
~~Total~~	$	—	$	~~(3)~~

~~Three Months Ended June 30, 2019~~
~~Derivatives designated as cash flow hedges~~
~~Interest rate~~	$	~~(13)~~	$	—
~~Total~~	$	~~(13)~~	$	—
~~Other derivative instruments~~
~~Electric commodity~~	$	—	$	26
~~Natural gas commodity~~	—		~~(2)~~
~~Total~~	$	—	$	24

~~Six Months Ended June 30, 2019~~
~~Derivatives designated as cash flow hedges~~
~~Interest rate~~	$	~~(22)~~	$	—
~~Total~~	$	~~(22)~~	$	—
~~Other derivative instruments~~
~~Electric commodity~~	$	—	$	4
~~Natural gas commodity~~	—		~~(2)~~
~~Total~~	$	—	$	2

Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: Pre-Tax Gains
(Losses) Recognized
During the Period in Income
(Millions of Dollars) Accumulated
Other
Comprehensive Loss Regulatory
Assets and (Liabilities)
Three Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate $ 2
^(a)
$ — $ —
Total $ 2 $ — $ —
Other derivative instruments
Commodity trading $ — $ — $ (3)
^(b)
Electric commodity — (3)
^(c)
—
Total $ — $ (3) $ (3)
Six Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate $ 4
^(a)
$ — $ —
Total $ 4 $ — $ —
Other derivative instruments
Commodity trading $ — $ — $ (5)
^(b)
Electric commodity — (7)
^(c)
—
Natural gas commodity — 5
^(d)
(6)
^(d)
Total $ — $ (2) $ (11)
Three Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate $ 1
^(a)
$ — $ —
Total $ 1 $ — $ —
Other derivative instruments
Commodity trading $ — $ — $ 5
^(b)
Total $ — $ — $ 5
Six Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate $ 2
^(a)
$ — $ —
Total $ 2 $ — $ —
Other derivative instruments
Commodity trading $ — $ — $ 4
^(b)
Electric commodity — 1
^(c)
—
Natural gas commodity — (1)
^(d)
(4)
^(d)
Total $ — $ — $ —

^(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 ~~three and~~ six months ended June 30, ~~2020~~2021 and ~~2019~~2020 included 0 settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Remaining settlement losses for both the ~~three and~~ six months ended June 30, 2021 and 2020 ~~and 2019 related~~relate to natural gas operations and were 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.

~~Table of Contents~~

Xcel Energy had 0 derivative instruments designated as fair value hedges during the three and six months ended June 30, ~~2020~~2021 and ~~2019.~~2020.

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, or for~~agencies. At June 30, 2021 and Dec. 31, 2020, there were $6 million and $4 million of derivative liabilities with such underlying contract provisions, respectively. Certain contracts also contain cross default ~~contractual~~ 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, ~~2020~~2021 and Dec. 31, ~~2019,~~2020, there were $8approximately $69 million and $7$60 million of derivative ~~instruments in a liability position~~liabilities with such underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. ~~Provisions~~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 0 collateral posted related to adequate assurance clauses in derivative contracts as of June 30, ~~2020~~2021 and Dec. 31, ~~2019~~2020.

Table of Contents

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


		June 30, 2020																									Dec. 31, 2019																																		June 30, 2021											Dec. 31, 2020
		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										Netting ^(a)			(Millions of Dollars)			Level 1	Level 2		Level 3		Fair Value Total														Level 2				Level 3				Fair Value Total
Current derivative assets	Current derivative assets																												Current derivative assets
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	5	$	52	$	11	$	68	$	(50)	$	18	$	3	$	51		$	24		$	78		$	(52)	$	26	Commodity trading	$	17		$	178		$	11		$	206	$	(168)	$	38			$	2			$	67			$	1			$	70			$	(52)			$	18
Electric commodity	Electric commodity	—		—		46		46		(2)		44		—		—			21			21			(1)		20		Electric commodity	0			0			98			98		(1)		97		0				0				20				20				(1)				19
Natural gas commodity	Natural gas commodity	—		7		—		7		—		7		—		6			—			6			—		6		Natural gas commodity	0			10			0			10		0		10		0				9				0				9				0				9
Total current derivative assets	Total current derivative assets	$	5	$	59	$	57	$	121	$	(52)	69		$	3	$	57		$	45		$	105		$	(53)	52		Total current derivative assets	$	17		$	188		$	109		$	314	$	(169)	145		$	2			$	76			$	21			$	99			$	(53)			46
PPAs ^(b)	PPAs ^(b)											3															3		PPAs (b)														3																						3
Current derivative instruments	Current derivative instruments											$	72														$	55	Current derivative instruments														$	148																					$	49
Noncurrent derivative assets	Noncurrent derivative assets																												Noncurrent derivative assets
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	11	$	42	$	23	$	76	$	(49)	$	27	$	9	$	38		$	7		$	54		$	(45)	$	9	Commodity trading	$	10		$	117		$	82		$	209	$	(125)	$	84	$	8			$	66			$	8			$	82			$	(62)			$	20

Total noncurrent derivative assets	Total noncurrent derivative assets	$	11	$	42	$	23	$	76	$	(49)	27		$	9	$	38		$	7		$	54		$	(45)	9		Total noncurrent derivative assets	$	10		$	117		$	82		$	209	$	(125)	84		$	8			$	66			$	8			$	82			$	(62)			20
PPAs ^(b)	PPAs ^(b)											11															13		PPAs (b)														8																						10
Noncurrent derivative instruments	Noncurrent derivative instruments											$	38														$	22	Noncurrent derivative instruments														$	92																					$	30


		June 30, 2020																									Dec. 31, 2019																											June 30, 2021									Dec. 31, 2020
		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										Netting ^(a)			(Millions of Dollars)			Level 1	Level 2		Level 3		Fair Value Total								Level 2			Level 3			Fair Value Total
Current derivative liabilities	Current derivative liabilities																												Current derivative liabilities

Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	6	$	54	$	8	$	68	$	(50)	$	18	$	4	$	59		$	15		$	78		$	(63)	$	15	Commodity trading	$	20		$	188		$	12		$	220	$	(175)	$	45	$	4	$	64	$	17	$	85		$	(58)		$	27
Electric commodity	Electric commodity	—		—		2		2		(2)		—		—		—			1			1			(1)		—		Electric commodity	0			0			1			1		(1)		0		0		0		1		1			(1)			0
Natural gas commodity	Natural gas commodity	—		5		—		5		—		5		—		5			—			5			—		5		Natural gas commodity	0			3			0			3		0		3		0		9		0		9			0			9
Total current derivative liabilities	Total current derivative liabilities	$	6	$	59	$	10	$	75	$	(52)	23		$	4	$	64		$	16		$	84		$	(64)	20		Total current derivative liabilities	$	20		$	191		$	13		$	224	$	(176)	48		$	4	$	73	$	18	$	95		$	(59)		36
PPAs ^(b)	PPAs ^(b)											17															18		PPAs (b)														17														17
Current derivative instruments	Current derivative instruments											$	40														$	38	Current derivative instruments														$	65													$	53
Noncurrent derivative liabilities	Noncurrent derivative liabilities																												Noncurrent derivative liabilities
Other derivative instruments:	Other derivative instruments:																									Other derivative instruments:
Commodity trading	Commodity trading	$	4	$	95	$	36	$	135	$	(20)	$	115	$	2	$	79		$	32		$	113		$	(13)	$	100	Commodity trading	$	7		$	116		$	107		$	230	$	(132)	$	98	$	3	$	58	$	60	$	121		$	(47)		$	74
Total noncurrent derivative liabilities	Total noncurrent derivative liabilities	$	4	$	95	$	36	$	135	$	(20)	115		$	2	$	79		$	32		$	113		$	(13)	100		Total noncurrent derivative liabilities	$	7		$	116		$	107		$	230	$	(132)	98		$	3	$	58	$	60	$	121		$	(47)		74
PPAs ^(b)	PPAs ^(b)											66															75		PPAs (b)														49														57
Noncurrent derivative instruments	Noncurrent derivative instruments											$	181														$	175	Noncurrent derivative instruments														$	147													$	131

^(a)Xcel Energy nets derivative instruments and related collateral inon its consolidated balance ~~sheet~~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, ~~2020~~2021 and Dec. 31, ~~2019.~~2020. At both June 30, ~~2020~~2021 and Dec. 31, ~~2019,~~2020, derivative assets and liabilities include ~~$32~~$15 million of obligations to return cash ~~collateral~~collateral. At June 30, 2021 and Dec. 31, 2020, derivative assets and liabilities include rights to reclaim cash collateral of $4$29 million and ~~$11~~$6 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.

Table of Contents

Changes in Level 3 commodity derivatives:


		Three Months Ended June 30							Three Months Ended June 30
(Millions of Dollars)	(Millions of Dollars)	2020		2019		(Millions of Dollars)	2021		2020
Balance at April 1	Balance at April 1	$	4	$	(7)	Balance at April 1	$	(13)	$	4
Purchases	Purchases	37		34		Purchases	63		37
Settlements	Settlements	(25)		(16)		Settlements	(32)		(25)
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)	9		7		Gains recognized in earnings (a)	9		9
Net gains recognized as regulatory assets and liabilities	Net gains recognized as regulatory assets and liabilities	9		10		Net gains recognized as regulatory assets and liabilities	44		9
Balance at June 30	Balance at June 30	$	34	$	28	Balance at June 30	$	71	$	34

		Six Months Ended June 30							Six Months Ended June 30
(Millions of Dollars)	(Millions of Dollars)	2020		2019		(Millions of Dollars)	2021		2020
Balance at Jan. 1	Balance at Jan. 1	$	4	$	29	Balance at Jan. 1	$	(49)	$	4
Purchases	Purchases	49		38		Purchases	63		49
Settlements	Settlements	(42)		(27)		Settlements	(48)		(42)
Net transactions recorded during the period:	Net transactions recorded during the period:					Net transactions recorded during the period:
Gains (losses) recognized in earnings ^(a)		14		(11)
Net gains (losses) recognized as regulatory assets and liabilities		9		(1)
Gains recognized in earnings (a)						Gains recognized in earnings (a)	47		14
Net gains recognized as regulatory assets and liabilities						Net gains recognized as regulatory assets and liabilities	58		9
Balance at June 30	Balance at June 30	$	34	$	28	Balance at June 30	$	71	$	34

^(a)~~Amounts~~Presented amounts relate to ~~commodity derivatives~~instruments held at the end of the period. The consolidated income statement also includes gains and losses on Level 1 and 2 instruments, and Level 3 instruments settled during the period.

Xcel Energy recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for the ~~three and~~ six months ended June 30, ~~2020~~2021 and ~~2019.~~2020.

Fair Value of Long-Term Debt

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


		June 30, 2020						Dec. 31, 2019							June 30, 2021				Dec. 31, 2020
(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	$	20,564	$	24,327	$	18,109	$	20,227	Long-term debt, including current portion	$	21,497	$	24,686	$	20,066	$	24,412

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, ~~2020~~2021 and Dec. 31, ~~2019,~~2020 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 June 30
		2020		2019		2020		2019			2021		2020		2021		2020
(Millions of Dollars)	(Millions of Dollars)	Pension Benefits						Postretirement Health Care Benefits						(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	Service cost	$	24	$	22	$	—	$	—	Service cost	$	26	$	24	$	1	$	0
Interest cost ^(a)	Interest cost ^(a)	31		36		5		6		Interest cost (a)	26		31		3		5
Expected return on plan assets ^(a)	Expected return on plan assets ^(a)	(52)		(51)		(5)		(5)		Expected return on plan assets (a)	(51)		(52)		(5)		(5)
Amortization of prior service credit ^(a)	Amortization of prior service credit ^(a)	(1)		(1)		(2)		(3)		Amortization of prior service credit (a)	(1)		(1)		(2)		(2)
Amortization of net loss ^(a)	Amortization of net loss ^(a)	25		22		1		1		Amortization of net loss (a)	27		25		2		1

Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	27		28		(1)		(1)		Net periodic benefit cost (credit)	27		27		(1)		(1)
Credits not recognized due to effects of regulation		1		1		1		—
Effects of regulation										Effects of regulation	0		1		0		1
Net benefit cost (credit) recognized for financial reporting	Net benefit cost (credit) recognized for financial reporting	$	28	$	29	$	—	$	(1)	Net benefit cost (credit) recognized for financial reporting	$	27	$	28	$	(1)	$	0


	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)

Six Months Ended June 30
2020 2019 2020 2019
(Millions of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 45 $ 43 $ 1 $ 1
Interest cost ^(a)
68 72 9 11
Expected return on plan assets^(a)
(103) (102) (10) (11)
Amortization of prior service credit ^(a)
(2) (2) (4) (5)
Amortization of net loss^(a)
47 44 2 3
Net periodic benefit cost (credit) 55 55 (2) (1)
Credits not recognized due to effects
of regulation 2 2 1 1
Net benefit cost (credit) recognized for financial reporting $ 57 $ 57 $ (1) $ —

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

In January ~~2020,~~2021, contributions of ~~$150~~$125 million were made across 4 of Xcel Energy’s pension ~~plans.~~plans. Xcel Energy does not expect additional pension contributions during ~~2020.~~2021.


10. Commitments and Contingencies

The following ~~include~~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, ~~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. ~~Unless otherwise required by GAAP, legal~~Legal fees are generally expensed as incurred.

Table of Contents

Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel ~~Energy Inc.~~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 active which include an MDL 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. — ~~In February 2019,~~The trial has been vacated and will be rescheduled after the ~~case was remanded back to~~court rules on the ~~U.S. District Court in Wisconsin. Plaintiffs are seeking~~pending motions for reconsideration and for class certification. ~~It is uncertain when the court will rule on this issue.~~

~~Table of Contents~~

Xcel Energy has concluded that a loss is remote for ~~both~~the remaining ~~lawsuits.~~

~~Rate Matters~~

~~MEC Transactions~~ — ~~In January 2020, Xcel Energy, Inc. purchased MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company (a subsidiary of Southern Company).~~lawsuit.

In July 2020, Xcel Energy sold MEC to Southwest Generation for $680 million, subject to working capital adjustments. Proceeds from the sale will primarily be used to reduce Xcel Energy’s overall financing needs.

The assets and liabilities of MEC, including plant assets and working capital, were classified as held for sale at June 30, 2020 pending the sale of the facility in July 2020. Amounts included in the consolidated balance sheet were classified as follows:


~~(Millions of Dollars)~~	~~June 30, 2020~~

~~Prepayments and other current assets~~	$	24
~~Other assets~~	~~644~~
~~Total assets~~	~~668~~

~~Other current liabilities~~	2
~~Other deferred credits and other liabilities~~	9
~~Total liabilities~~	$	11

~~NSP-Minnesota~~ — Sherco — In ~~NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional~~2018, NSP-Minnesota and ~~subject to further review following conclusion of litigation commenced by NSP-Minnesota,~~ SMMPA (Co-owner of Sherco Unit 3) ~~and insurance companies against GE.~~

~~In 2018, NSP-Minnesota and SMMPA~~ reached a settlement with ~~GE.~~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 ~~the GE~~ settlement proceeds ~~back~~ to customers through the FCA. ~~The insurance providers continued their litigation against GE and the case went to trial.~~

In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial.

In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.

In March 2019, the MPUC approved NSP-Minnesota’s ~~proposal to~~settlement refund proposal. Additionally, the ~~GE settlement proceeds back to customers through the FCA. It also~~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 ~~the~~an appeal pending ~~litigation~~ between GE and NSP-Minnesota’s insurers. ~~The lower~~In February 2020, the Minnesota Court of Appeals affirmed the district court’s ~~decision was affirmed on appeal.~~judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.

On In April ~~28,~~ 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.

In ~~accordance with a prior MPUC order,~~January 2021, the OAG and DOC recommended that NSP-Minnesota ~~will now make a compliance filing on Aug. 21, 2020, detailing all~~refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota subsequently filed its response, asserting that ~~resulted from the outage and all insurance recoveries received by NSP-Minnesota~~it acted prudently in connection with the ~~outage. The~~Sherco Unit 3 outage, the MPUC has ~~indicated it intends~~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 ~~review the prudence of the Company’s actions and costs in connection with the outage now that the ligation~~this matter is ~~complete. The MPUC, however, has not specified what process it will use to complete that review.~~deemed remote.

Westmoreland Arbitration — ~~On Nov. 14,~~In November 2014, ~~certain~~ insurers for Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, ~~and other entities (SMMPA~~SMMPA and Western Fuels ~~Association),~~Association, seeking recovery of alleged $36 million of business losses ~~following the Nov. 19, 2011 incident involving~~due to a turbine failure ~~of a low-pressure turbine in~~at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause ~~of the applicable coal supply agreement~~ 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. ~~Westmoreland’s insurers quantified their losses as approximately $36 million.~~

All parties tolled the arbitration pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. That litigation has been resolved and notice of resolution was served July 6, 2020, triggering the arbitration to resume.

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 in the coal supply agreement and intends to defend the matter.~~provision. It is uncertain when a final resolution will occur, but it is unlikely ~~that~~ an arbitration hearing will take place before the fourth quarter 2021. At ~~June 30, 2020,~~this stage of the proceeding, a reasonable estimate of ~~the~~ damages or range of damages cannot be determined.

MISO ROE Complaints — In November 2013 and February 2015, ~~customers~~customer groups filed two ROE complaints against MISO TOs, ~~including~~which includes NSP-Minnesota and NSP-Wisconsin.

The first complaint ~~argued for~~requested a reduction in ~~the~~ base ROE ~~in MISO~~ 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 ~~sought to reduce~~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 ~~(10.82% with the RTO adder)~~ 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.~~D.C Circuit subsequently vacated and remanded ~~FERC~~ Opinion No. ~~531, which had established the ROE methodology on which the September 2016 FERC order was based.~~551.

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In November 2019, the FERC issued ~~Opinion~~an order (Opinion No. ~~569 adopting a new ROE methodology and settling~~569), which set the MISO base ROE at 9.88% ~~(10.38% with the RTO adder)~~, effective Sept. 28, 2016 and for the ~~refund period in the~~ first ~~complaint.~~complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for ~~rehearing.~~rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds.

~~FERC accepted the requests for rehearing in January 2020.~~

In March 2020, the FERC issued a Notice of Proposed Rulemaking regarding changes to its policies for transmission incentives, including a proposal to increase the RTO participation adder from 50 to 100 basis points and to make the adder available regardless of whether a utility’s ongoing participation in the RTO is voluntary or required by legislation or a regulator.

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

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

The MISO TOs and various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit with initial briefs filed in March 2021 and final briefs 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 of the adder would ultimately be offset by an increase in retail rates, following future rate cases.

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SPP OATT Upgrade Costs — ~~Under the SPP OATT, costs~~Costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the ~~upgrade.~~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 ~~these~~ previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund ~~the~~ 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 appeals in support of the FERC. Any 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 ~~against~~asserting SPP ~~asserting that SPP has~~ assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS ~~complaint in its entirety, and finding SPP’s calculations to be consistent with the SPS Tariff.~~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 ~~amounts~~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 appeal is stayed pending the outcome of the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.

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 (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 ~~2020,~~2021, the ~~D.C. Circuit~~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 ~~an unrelated proceeding (Allegheny Defense Project v. FERC), which held that FERC’s longstanding use~~expected in the third quarter of ~~tolling orders to extend FERC’s deadline to act on the merits of requests for rehearing is improper. The effect on this decision on tolling orders previously issued by FERC is unclear.~~2021.

Environmental

MGP, Landfill and Disposal Sites

~~Ashland MGP Site~~ — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019 and restoration activities were completed in 2020. Groundwater treatment activities will continue for many years.

The cost estimate for remediation and restoration of the entire site is approximately $199 million. At June 30, 2020 and Dec. 31, 2019, NSP-Wisconsin had a total liability of $21 million and $23 million, respectively, for the entire site.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site and application of a 3% carrying charge to the regulatory asset.

~~Rice Yards (Denver) MGP Site —~~ PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard and MGP operations.

In June 2020, PSCo resolved claims by the current property owner and agreed to contribute up to a maximum of $9 million towards future environmental investigation, remediation and mitigation measures over the next 15 years.

~~In addition to the Rice Yards and Ashland Sites,~~ Xcel Energy is ~~currently~~ investigating, remediating or performing post-closure actions at ~~12 other~~13 MGP, landfill or other disposal sites across its service territories.

Xcel Energy has recognized its best estimate of costs/liabilities ~~that will result~~ from final resolution of these issues, however, the outcome and timing is 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 98 regulated ash units in operation.

Xcel Energy is conducting groundwater sampling and ~~where appropriate,~~monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. ~~In 2019, groundwater monitoring consistent with the CCR Rule was conducted.~~ In NSP-Minnesota, 0 results above the groundwater protection standards in the rule were identified. In PSCo, ~~statistically significant levels~~increases above background concentrations were detected at 4 locations. ~~Subsequently, assessment monitoring samples were collected at these locations and, based~~Based on ~~the results,~~further assessments, PSCo is evaluating options for corrective action at 2 ~~locations. At~~locations, 1 ~~location, monitoring results indicate~~of which indicates potential offsite impacts to groundwater. ~~Until PSCo completes its assessment, it~~The total cost is uncertain, ~~what impact, if any, there~~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. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.

PSCo also built an alternative collection and treatment system to remove the Comanche Station bottom ash pond from service. The total cost of the alternate treatment system is approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline, but was not able to remove the pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the EPA. PSCo will ~~be on~~also now proceed with closure of the ~~operations, financial condition or cash flows.~~pond, with an estimated cost of $3 million.

Closure costs for existing impoundments are included in the calculation of the ARO.

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~~In August 2018, the D.C. Circuit ruled~~Leases

Xcel Energy evaluates contracts that ~~the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments)~~may contain leases, including PPAs and arrangements for the ~~storage or disposal~~use of ~~coal ash. In November 2019,~~office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the ~~EPA proposed rules in response~~exclusive right to ~~this decision. If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for 1 impoundment at an estimated cost~~control the use of $4a specific asset.

Components of lease expense:


	Three Months Ended June 30
(Millions of Dollars)	2021		2020
Operating leases
PPA capacity payments	$	56	$	43
Other operating leases (a)	9		9
Total operating lease expense (b)	$	65	$	52
Finance leases
Amortization of ROU assets	$	2	$	2
Interest expense on lease liability	4		4
Total finance lease expense	$	6	$	6

(a)Includes short-term lease expense of $2 million and the construction of a new impoundment at the cost of $9 million. In 2019, NSP-Minnesota initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service,$1 million for 2021 and ~~closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated.~~2020, respectively.

In addition, the rules proposed by the EPA under the D.C. Circuit ruling may require PSCo to expedite the closure of 1 coal ash impoundment that was not previously required to close. In March 2020, the EPA published a proposed CCR Rule amendment that, if adopted, would allow unlined impoundments that ‘perform as effectively’ as lined ones to continue to operate under a state or federal CCR permit program. PSCo is pursuing options to provide alternative storage(b)PPA capacity ~~consistent with the CCR Rule until the generating units are retired in 2025.~~

~~Closure costs for existing impoundments~~payments are included in electric fuel and purchased power on the ~~calculation~~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 of $3 million and $2 million for 2021 and 2020, respectively.

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

~~Leases~~

~~Operating lease liabilities at Dec. 31, 2019 include a present value~~Commitments under operating and finance leases as of ~~remaining lease payments of approximately $400 million for the MEC PPAs. At~~ June 30, ~~2020, NSP-Minnesota operating lease liabilities and~~2021:


(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)
Total minimum obligation	$	1,532	$	196	$	1,728	$	249
Interest component of obligation	(235)		(37)		(272)		(175)
Present value of minimum obligation	$	1,297	159		1,456		74
Less current portion					(220)		(3)
Noncurrent operating and finance lease liabilities					$	1,236	$	71

(a)Excludes certain amounts related ~~right-of-use assets are eliminated from~~to Xcel Energy’s ~~consolidated balance sheet following the completed January 2020 purchase of MEC by Xcel Energy.~~

50% ownership interest in WYCO.

VIEs

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the ~~energy that they purchase.~~energy. These specific PPAs create a variable interest in the IPP.

The utility subsidiaries had ~~approximately 3,342 MW and 3,986~~approximately 4,062 MW of capacity under long-term PPAs at both June 30, ~~2020~~2021 and Dec. 31, ~~2019, respectively,~~2020 with entities that have been determined to be VIEs. Xcel Energy concluded that these entities are not required to be consolidated in its ~~consolidated~~ financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. ~~Agreements~~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 ~~specified agreements or transactions.~~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, ~~2020~~2021 and Dec. 31, ~~2019,~~2020, Xcel Energy Inc. and its subsidiaries had 0 assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were approximately $60 million and $62 million at June 30, ~~2020~~2021 and Dec. 31, ~~2019.~~2020, 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 ~~terms of~~ duration and amount. Maximum future payments under these indemnifications cannot be reasonably ~~estimated as the dollar amounts are often not explicitly stated.~~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, ~~2020~~2021 and ~~2019:~~2020:

Three Months Ended June 30, 2020 Three Months Ended June 30, 2019
(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 $ (88) $ (60) $ (148) $ (66) $ (61) $ (127)
Other comprehensive (loss) gain before reclassifications (net of taxes of $—, $—, $(3) and $—, respectively) — — — (10) 1 (9)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $—, $— and $—, respectively) ^(a)
1 — 1 1 — 1
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) ^(b)
— 2 2 — — —
Net current period other comprehensive income (loss) 1 2 3 (9) 1 (8)
Accumulated other comprehensive loss at June 30 $ (87) $ (58) $ (145) $ (75) $ (60) $ (135)

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	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)


	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)

Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
(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 $ (80) $ (61) $ (141) $ (60) $ (64) $ (124)
Other comprehensive (loss) gain before reclassifications (net of taxes of $(3), $—, $(5) and $1, respectively) (10) — (10) (17) 3 (14)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $—, $— and $—, respectively) ^(a)
3 — 3 2 — 2
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) ^(b)
— 3 3 — 1 1
Net current period other comprehensive (loss) income (7) 3 (4) (15) 4 (11)
Accumulated other comprehensive loss at June 30 $ (87) $ (58) $ (145) $ (75) $ (60) $ (135)

^(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; and~~operations.

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

Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel, ~~and~~ investments in rental housing projects that qualify for low-income housing tax credits and the operations of ~~MEC.~~MEC until July 2020.

Xcel Energy had equity method investments ~~in unconsolidated subsidiaries~~ of ~~$155~~$189 million and $165 million as of June 30, ~~2020~~2021 and Dec. 31, ~~2019~~2020, respectively, included in the natural gas utility and all other segments.

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

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

~~Xcel Energy’s segment information for the three and six months ended June 30:~~

Three Months Ended June 30
(Millions of Dollars) 2020 2019
Regulated Electric
Operating revenues from external customers $ 2,286 $ 2,249
Intersegment revenue 1 1
Total revenues $ 2,287 $ 2,250
Net income 289 249
Regulated Natural Gas
Operating revenues from external customers $ 280 $ 308
Net income 20 23
All Other
Total operating revenue $ 20 $ 20
Net loss (22) (34)
Consolidated Total
Total revenue $ 2,587 $ 2,578
Reconciling eliminations (1) (1)
Total operating revenues $ 2,586 $ 2,577
Net income 287 238

Table of ~~Contents~~Conten t s

Six Months Ended June 30
(Millions of Dollars) 2020 2019
Regulated Electric
Operating revenues from external customers $ 4,489 $ 4,574
Intersegment revenue 1 1
Total revenues $ 4,490 $ 4,575
Net income 516 482
Regulated Natural Gas
Operating revenues from external customers $ 863 $ 1,102
Intersegment revenue 1 1
Total revenues $ 864 $ 1,103
Net income 111 128
All Other
Total operating revenue $ 45 $ 42
Net loss (45) (57)
Consolidated Total
Total revenue $ 5,399 $ 5,720
Reconciling eliminations (2) (2)
Total operating revenues $ 5,397 $ 5,718
Net income 582 553
Xcel Energy’s segment information:


	Three Months Ended June 30
(Millions of Dollars)	2021		2020
Regulated Electric
Operating revenues from external customers	$	2,597	$	2,286
Intersegment revenue	1		1
Total revenues	$	2,598	$	2,287
Net income	304		289
Regulated Natural Gas
Total revenues	$	449	$	280
Net income	33		20
All Other
Total revenues	$	22	$	20
Net loss	(26)		(22)
Consolidated Total
Total revenues	$	3,069	$	2,587
Reconciling eliminations	(1)		(1)
Total operating revenues	$	3,068	$	2,586
Net income	311		287


	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 ~~excludes (or includes) amounts that are adjusted from~~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 ~~the~~ net income or loss, ~~of each subsidiary,~~ 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 offor such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

Table of Contents

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

For the three and six months ended June 30, ~~2020~~2021 and ~~2019,~~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.

~~Table of Contents~~

~~GAAP and ongoing~~Summarized diluted EPS for Xcel Energy:


		Three Months Ended June 30						Six Months Ended June 30							Three Months Ended June 30				Six Months Ended June 30
Diluted Earnings (Loss) Per Share	Diluted Earnings (Loss) Per Share	2020		2019		2020		2019		Diluted Earnings (Loss) Per Share	2021		2020		2021		2020
PSCo	PSCo	$	0.21	$	0.20	$	0.45	$	0.47	PSCo	$	0.25	$	0.21	$	0.56	$	0.45
NSP-Minnesota	NSP-Minnesota	0.22		0.19		0.43		0.41		NSP-Minnesota	0.21		0.22		0.45		0.43
SPS	SPS	0.14		0.11		0.22		0.22		SPS	0.13		0.14		0.23		0.22
NSP-Wisconsin	NSP-Wisconsin	0.02		0.02		0.09		0.06		NSP-Wisconsin	0.03		0.02		0.09		0.09
Equity earnings of unconsolidated subsidiaries		0.01		0.01		0.02		0.02
Earnings from equity method investments - WYCO										Earnings from equity method investments - WYCO	0.01		0.01		0.02		0.02
Regulated utility ^(a)	Regulated utility ^(a)	0.60		0.53		1.20		1.18		Regulated utility (a)	0.62		0.60		1.35		1.20
Xcel Energy Inc. and Other	Xcel Energy Inc. and Other	(0.07)		(0.06)		(0.10)		(0.11)		Xcel Energy Inc. and Other	(0.04)		(0.07)		(0.10)		(0.10)

Total ^(a)	Total ^(a)	$	0.54	$	0.46	$	1.10	$	1.07	Total (a)	$	0.58	$	0.54	$	1.25	$	1.10

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

Summary of Earnings

Xcel Energy — Xcel Energy’s earnings increased ~~$0.08~~$0.04 per share for the second quarter of ~~2020~~2021 and ~~$0.03~~increased $0.15 per share year-to-date. Earnings primarily reflect ~~management’s actions~~higher electric and natural gas margins (driven by capital investment recovery, regulatory outcomes and weather-normalized sales growth as compared to ~~reduce O&M to offset the impact from COVID-19 and favorable weather,~~2020, which was more adversely impacted by COVID-19). These drivers were partially offset by higher depreciation, O&M expenses, interest charges and ~~interest charges. Income~~lower AFUDC.

PSCo — Earnings increased $0.04 per share for the second 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 capital investment recovery and regulatory outcomes), partially offset by additional depreciation and other taxes ~~were lower primarily due to~~(other than income taxes).

NSP-Minnesota — Earnings decreased $0.01 per share for the second quarter of 2021 and increased $0.02 per share year-to-date. The increase in year-to-date earnings reflects higher ~~PTCs, which are credited to customers, resulting in lower~~ electric margin (primarily capital investment recovery), partially offset by increased depreciation and ~~do not materially impact earnings.~~O&M expenses.

~~PSCo~~SPS — Earnings decreased $0.01 per share for the second quarter of 2021 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), partially offset by increased depreciation and O&M expenses.

NSP-Wisconsin — Earnings increased $0.01 per share for the second quarter of 2020 and decreased $0.02 per share year-to date. The decrease in year-to-date earnings was driven by lower sales and demand revenue primarily due to COVID-19, higher depreciation, interest charges and lower natural gas margins due to unfavorable weather, partially offset by higher AFUDC, an increase in electric margins (regulatory outcomes offset lower sales due to COVID-19) and lower O&M.

~~NSP-Minnesota~~ — Earnings increased $0.03 per share for the second quarter of 2020 and $0.02 year-to-date. The increase in year-to-date earnings primarily reflects lower O&M and income taxes, partially offset by lower electric margins (reflecting lower sales from COVID-19) and natural gas margins as well as higher depreciation. Lower electric margins were due primarily to increased PTCs flowed back to customers (offset in income tax) and decreased sales, partially offset by non-fuel riders.

~~SPS~~ — ~~Earnings increased $0.03 per share for the second quarter of 2020~~2021 and were flat year-to-date. Year-to-date earnings were driven by lower O&M and income taxes, offset by lower electric margin and increased depreciation. Lower electric margins were attributable to lower sales from COVID-19, increased PTCs flowed back to customers (offset in income tax) and a 2019 NMPRC revised order eliminating a $10 million retroactive refund of tax reform benefits, partially offset by an increase in wholesale transmission revenue.

~~NSP-Wisconsin~~ — Earnings were flat for the second quarter of 2020 and increased $0.03 per share year-to-date. The increase in year-to-date earnings was driven by lower O&M and income taxes, as well as higher electric margin (due primarily to regulatory outcomes which offset lower sales from COVID-19), partially offset by lower natural gas margins due to unfavorable weather and increased depreciation.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding ~~company.~~company and earnings from EIP funds equity method investments.

Changes in GAAP and Ongoing Diluted EPS

Components significantly contributing to changes in ~~2020~~2021 EPS compared ~~with the same period in 2019:~~to 2020:

Diluted Earnings (Loss) Per Share Three Months Ended June 30 Six Months Ended June 30
GAAP and ongoing diluted EPS — 2019 $ 0.46 $ 1.07
Components of change — 2020 vs. 2019
Lower ETR ^(a)
0.07 0.10
Lower O&M 0.05 0.08
Higher AFUDC 0.03 0.04
Higher electric margin^(b)
0.02 0.02
Higher depreciation and amortization (0.05) (0.09)
Higher interest charges (0.03) (0.04)
Lower natural gas margins — (0.03)
Lower other income (expense), net — (0.02)
Other (net) (0.01) (0.03)
GAAP and ongoing diluted EPS — 2020 $ 0.54 $ 1.10


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

^(a)Includes PTCs and ~~tax reform~~plant regulatory amounts, which are primarily offset in electric margin.

^(b)~~The period-over-period change in electric margin was negatively impacted by reductions in sales and demand. See table below:~~

Diluted Earnings (Loss) Per Share Three Months Ended June 30 Six Months Ended June 30
Electric margin (excluding reductions in sales and demand) $ 0.09 $ 0.09
Reductions in sales and demand ^(a)
(0.07) (0.07)
Higher electric margins $ 0.02 $ 0.02

^(a) ~~Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up.~~

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 and Colorado predominately mitigate the positive and adverse impacts of weather.

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.

~~Table of Contents~~

Normal weather conditions are defined as either the 10, 20 or ~~30-year~~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.

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


		Three Months Ended June 30										Six Months Ended June 30											Three Months Ended June 30				Six Months Ended June 30
		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019			2021 vs. Normal		2020 vs. Normal		2021 vs. 2020		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020
HDD	HDD	2.2	%	16.9	%	(11.8)	%	(4.1)	%	12.8	%	(14.4)	%	HDD	1.7	%	2.2	%	(1.1)	%	1.4	%	(4.1)	%	4.9	%
CDD	CDD	22.4		(45.2)		191.2		22.5		(45.5)		139.9		CDD	6.8		22.4		(26.9)		3.0		22.5		(16.2)
THI	THI	15.0		(26.7)		63.6		14.7		(26.9)		63.6		THI	88.9		15.0		67.7		88.4		14.7		67.7

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 June 30				Six Months Ended June 30
		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019		2020 vs. Normal		2019 vs. Normal		2020 vs. 2019			2021 vs. Normal		2020 vs. Normal		2021 vs. 2020		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020
Retail electric	Retail electric	$	0.028	$	(0.024)	$	0.052	$	0.017	$	(0.005)	$	0.022	Retail electric	$	0.056	$	0.028	$	0.028	$	0.055	$	0.017	$	0.038
Decoupling and sales true-up	Decoupling and sales true-up	(0.014)		0.006		(0.020)		(0.009)		0.001		(0.010)		Decoupling and sales true-up	(0.044)		(0.014)		(0.030)		(0.041)		(0.009)		(0.032)
Electric total	Electric total	$	0.014	$	(0.018)	$	0.032	$	0.008	$	(0.004)	$	0.012	Electric total	$	0.012	$	0.014	$	(0.002)	$	0.014	$	0.008	$	0.006
Firm natural gas	Firm natural gas	0.001		0.004		(0.003)		(0.006)		0.022		(0.028)		Firm natural gas	0.002		0.001		0.001		0.005		(0.006)		0.011
Total	Total	$	0.015	$	(0.014)	$	0.029	$	0.002	$	0.018	$	(0.016)	Total	$	0.014	$	0.015	$	(0.001)	$	0.019	$	0.002	$	0.017

Sales ~~Growth (Decline)~~ — Sales growth (decline) for actual and weather-normalized sales in ~~2020~~2021 compared to ~~the same period in 2019:~~2020:


		Three Months Ended June 30																			Three Months Ended June 30
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual ^(a)	Actual ^(a)											Actual ^(a)
Electric residential	Electric residential	13.5	%	10.2	%	13.4	%	10.8	%	11.9	%	Electric residential	—	%	6.1	%	(5.6)	%	2.7	%	1.9	%
Electric C&I	Electric C&I	(8.3)		(13.2)		(7.5)		(12.3)		(10.2)		Electric C&I	6.2		10.1		7.5		11.6		8.3
Total retail electric sales	Total retail electric sales	(1.7)		(6.6)		(4.4)		(6.5)		(4.5)		Total retail electric sales	3.9		8.7		5.2		8.9		6.3
Firm natural gas sales	Firm natural gas sales	(13.0)		0.4		N/A		(3.8)		(8.5)		Firm natural gas sales	18.8		(9.5)		N/A		(2.5)		8.3


		Three Months Ended June 30																			Three Months Ended June 30
		PSCo ^(b)		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-normalized ^(a)
Weather-Normalized												Weather-Normalized
Electric residential	Electric residential	6.1	%	5.7	%	3.3	%	4.9	%	5.4	%	Electric residential	0.7	%	(1.6)	%	(1.3)	%	(2.3)	%	(0.7)	%
Electric C&I	Electric C&I	(10.4)		(14.2)		(8.6)		(13.3)		(11.5)		Electric C&I	6.5		8.3		8.4		10.2		7.9
Total retail electric sales	Total retail electric sales	(5.4)		(8.5)		(6.9)		(8.6)		(7.1)		Total retail electric sales	4.4		5.0		6.8		6.5		5.3
Firm natural gas sales	Firm natural gas sales	(7.4)		2.7		N/A		3.1		(3.9)		Firm natural gas sales	12.7		(2.6)		N/A		6.8		7.6

Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual ^(a)
Electric residential 5.7 % 2.1 % 5.4 % 1.0 % 3.8 %
Electric C&I (4.0) (8.5) (2.2) (6.4) (5.4)
Total retail electric sales (1.0) (5.4) (1.1) (4.3) (2.9)
Firm natural gas sales (8.2) (10.4) N/A (12.0) (9.1)


	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															Six Months Ended June 30
		PSCo ^(b)		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo	NSP-Minnesota	SPS	NSP-Wisconsin	Xcel Energy
Weather-normalized ^(a)
Weather-Normalized												Weather-Normalized
Electric residential	Electric residential	3.4	%	2.7	%	1.9	%	3.0	%	2.9	%	Electric residential	2.9%	1.6%	1.4%	0.5%	2.0%
Electric C&I	Electric C&I	(5.0)		(8.7)		(2.7)		(6.5)		(5.8)		Electric C&I	0.4	0.4	0.2	3.8	0.6
Total retail electric sales	Total retail electric sales	(2.4)		(5.3)		(2.1)		(3.8)		(3.5)		Total retail electric sales	1.2	0.7	0.5	2.8	1.0
Firm natural gas sales	Firm natural gas sales	(1.4)		2.6		N/A		3.3		0.2		Firm natural gas sales	2.4	(1.6)	N/A	(0.6)	0.9

Six Months Ended June 30 (Leap Year Adjusted)
PSCo ^(b)
NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized ^(a)
Electric residential 2.8 % 2.2 % 1.3 % 2.4 % 2.3 %
Electric C&I (5.5) (9.2) (3.3) (7.1) (6.4)
Total retail electric sales (3.0) (5.8) (2.7) (4.4) (4.1)
Firm natural gas sales (2.2) 1.7 N/A 2.3 (0.7)

^(a)~~Higher residential sales and lower C&I sales were primarily attributable to COVID-19.~~

^(b)~~CPUC approved a historical 10-year weather normalization approach for retail electric, effective March 1, 2020.~~


	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 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated on a year-to-date basis as individuals working from home have just begun returning to the office.

•PSCo — Residential sales rose based on ~~higher use per customer from stay-at-home mandates and an increased number of customers. The C&I decline was due to lower use offsetting~~ an increase in the number of ~~C&I customers.~~customers combined with higher use per customer. The ~~decline~~growth in large C&I sales was primarily ~~due to~~led by the ~~shutdown of the economy from COVID-19, decreases~~service, agriculture, food and energy sectors, partially offset by a decrease in the manufacturing ~~and service industries, partially offset by an increase in the energy~~ sector.

•NSP-Minnesota — Residential sales growth reflects an increase in the number of customers combined with higher use per ~~customer from stay-at-home mandates and increased customer additions.~~customer. The ~~drop~~growth in C&I sales was ~~as a result of~~due to customer growth ~~offset by lower~~and slightly higher use per ~~customer. Decreased sales to C&I customers were due to the shutdown of the economy from COVID-19 and declines~~customer, primarily in the ~~energy,~~ manufacturing ~~and services sectors.~~sector.

•SPS — Residential sales rose based on an increase in the number of customers combined with higher use per customer. C&I sales increased due to ~~customer growth and~~ higher use per customer ~~from stay-at-home mandates. The decline in C&I sales was due~~and growth attributable to ~~shutdowns of~~ the ~~economy from COVID-19, declines in oil and natural gas extraction due to lower commodity prices and lower manufacturing, agriculture &~~ food ~~and services.~~sector, partially offset by losses within the energy sector.

•NSP-Wisconsin — Residential sales growth was attributable to customer additions and higher use per ~~customer from stay-at-home mandates and customer additions.~~customer. The ~~decline~~growth in C&I sales was ~~largely due to~~primarily led by increases in the ~~shutdown of the economy from COVID-19~~services, agriculture, food and ~~decreased sales to~~energy sectors, partially offset by a decrease in the manufacturing sector.

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

•Natural gas sales primarily reflect an increase in the number of customers combined with ~~lower~~slightly higher customer ~~use due to the shutdown of the economy from COVID-19.~~

use.

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Electric Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and ~~uranium used in the generation of electricity.~~uranium. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses.

In addition, electric customers receive a credit for PTCs generated, ~~in a particular period.~~which reduce electric revenue and margin.

Electric revenues and margin:


		Three Months Ended June 30						Six Months Ended June 30							Three Months Ended June 30				Six Months Ended June 30
(Millions of Dollars)	(Millions of Dollars)	2020		2019		2020		2019		(Millions of Dollars)	2021		2020		2021		2020
Electric revenues	Electric revenues	$	2,286	$	2,249	$	4,489	$	4,574	Electric revenues	$	2,597	$	2,286	$	5,467	$	4,489
Electric fuel and purchased power	Electric fuel and purchased power	(833)		(813)		(1,630)		(1,727)		Electric fuel and purchased power	(1,047)		(833)		(2,433)		(1,630)
Electric margin	Electric margin	$	1,453	$	1,436	$	2,859	$	2,847	Electric margin	$	1,550	$	1,453	$	3,034	$	2,859

Changes in electric margin:


(Millions of Dollars)	(Millions of Dollars)	Three Months Ended June 30, 2020 vs. 2019		Six Months Ended June 30, 2020 vs. 2019		(Millions of Dollars)	Three Months Ended June 30, 2021 vs. 2020		Six Months Ended June 30, 2021 vs. 2020
Regulatory rate outcomes (Colorado, Wisconsin and New Mexico)		$	21	$	34
Non-fuel riders						Non-fuel riders	$	89	$	133
Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota)						Regulatory rate outcomes (Texas, New Mexico, Colorado, Wisconsin and North Dakota)	34		78

Proprietary commodity trading, net of sharing — Winter Storm Uri						Proprietary commodity trading, net of sharing — Winter Storm Uri	—		27
Sales and demand (a)						Sales and demand (a)	24		10
Estimated impact of weather (net of decoupling/sales true-up)						Estimated impact of weather (net of decoupling/sales true-up)	(1)		5
Wholesale transmission revenue (net)	Wholesale transmission revenue (net)	20		25		Wholesale transmission revenue (net)	(8)		3
Non-fuel riders		11		24
Estimated impact of weather (net of decoupling/sales true-up)		21		8
PTCs flowed back to customers (offset by a lower ETR)		(31)		(53)
Sales and demand ^(a)		(47)		(46)
New Mexico tax reform related regulatory settlement (2019)		—		(10)
PTCs flowed back to customers (offset by lower ETR)						PTCs flowed back to customers (offset by lower ETR)	(42)		(79)
Other (net)	Other (net)	22		30		Other (net)	1		(2)
Total increase in electric margin	Total increase in electric margin	$	17	$	12	Total increase in electric margin	$	97	$	175

^(a)Sales ~~decline~~ excludes weather impact, net of decoupling/sales true-up, and ~~decrease in~~ demand ~~revenue~~ is net of sales true-up.

Natural Gas Margin

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

Natural gas revenues and margin:


		Three Months Ended June 30						Six Months Ended June 30							Three Months Ended June 30				Six Months Ended June 30
(Millions of Dollars)	(Millions of Dollars)	2020		2019		2020		2019		(Millions of Dollars)	2021		2020		2021		2020
Natural gas revenues	Natural gas revenues	$	280	$	308	$	863	$	1,102	Natural gas revenues	$	449	$	280	$	1,096	$	863
Cost of natural gas sold and transported	Cost of natural gas sold and transported	(86)		(112)		(371)		(591)		Cost of natural gas sold and transported	(218)		(86)		(517)		(371)
Natural gas margin	Natural gas margin	$	194	$	196	$	492	$	511	Natural gas margin	$	231	$	194	$	579	$	492

Changes in natural gas margin:

(Millions of Dollars) Three Months Ended June 30,
2020 vs. 2019 Six Months Ended June 30,
2020 vs. 2019
Estimated impact of weather $ (2) $ (19)
Transport sales — (2)
Regulatory rate outcomes (Wisconsin) — (2)
Retail sales decline (2) (1)
Infrastructure and integrity riders 4 5
Conservation revenue (offset in expenses) 2 3
Other (net) (4) (3)
Total decrease in natural gas margin $ (2) $ (19)


(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

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses ~~decreased $36~~increased $50 million, or ~~6.1%~~9.1%, for the second quarter and $55 million, or ~~4.6%, year-to-date, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19.~~4.9% year-to-date. Significant changes are summarized as follows:

(Millions of Dollars) Three Months Ended June 30,
2020 vs. 2019 Six Months Ended June 30,
2020 vs. 2019
Distribution $ (20) $ (30)
Employee benefits 6 (10)
Transmission (5) (6)
Generation (4) (6)
Strategic initiatives — 6
Other (net) (13) (9)
Total decrease in O&M expenses $ (36) $ (55)



(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

•~~Distribution~~The increase was primarily due to expenses ~~declined~~associated with new wind farms, software infrastructure and security costs, natural gas damage prevention, and timing of distribution expenses, partially offset by continuous improvement initiatives. Quarterly timing impacts also occurred throughout 2020 due to cost ~~mitigation efforts including allocation~~control initiatives to mitigate the adverse impact of ~~workforce, material and supply management, performance of maintenance and other items;~~

•~~Employee benefits were lower year-to-date primarily due to change in deferred compensation liability, offset in Other Income (Expense);~~

•~~Transmission expenses declined due to a reduction in labor related amounts and cost mitigation initiatives;~~

•~~Generation expenses were lower from timing of maintenance and overhauls at power plants and cost mitigation efforts, partially offset by an increase in wind related amounts;~~

•~~Strategic initiative amounts were higher year-to-date due to increased spending~~COVID-19 on ~~customer experience transformation program expenses and advanced grid infrastructure; and~~

•~~Other primarily includes deferred amounts associated with the Texas 2019 electric rate case and the outcome of the CPUC’s rehearing of the Colorado 2019 electric rate case.~~sales.

Depreciation and Amortization — Depreciation and amortization increased ~~$34~~$55 million, or ~~7.7%~~11.6%, for the second quarter and ~~$64~~$113 million or ~~7.3%, year-to-date. Increase~~12.1% year-to-date. The increase was primarily driven by ~~the Hale, Lake Benton, Foxtail and Blazing Star I~~several wind ~~facilities~~farms going into service, as well as normal system expansion. In addition, 2021 depreciation expense increased as a result of implementation of new depreciation rates ~~were increased~~ in ~~Colorado and New Mexico as part of regulatory outcomes in 2020.~~various states.

Other Income (Expense) — Other income (expense) ~~increased $3~~decreased $2 million for the second quarter and ~~decreased $13~~increased $15 million ~~year-to-date. Decrease is due~~year-to-date, which was largely related to ~~the performance of~~ rabbi trust ~~investments, which is~~performance primarily offset in O&M ~~expense (deferred compensation)~~expenses (compensation).

~~Table of Contents~~

AFUDC, Equity and Debt — AFUDC ~~increased $19~~decreased $25 million for the second quarter of 2021 and ~~$23~~$40 million year-to-date. ~~Increase~~The decrease was primarily ~~due to additional AFUDC recorded on~~driven by completion of various wind ~~projects currently under construction.~~projects.

Interest Charges — Interest charges increased ~~$19~~$4 million, or ~~10.1%~~1.9%, for the second quarter and ~~$28~~$10 million or ~~7.4%~~2.5% year-to-date. ~~Increase~~The increase was ~~primarily due~~largely attributable to higher long-term debt levels to fund capital investments and a term loan 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.

Income Taxes — Income ~~taxes decreased $37~~tax benefit increased $25 million for the second ~~quarter. Decrease~~quarter and $41 million year-to-date. The increase was primarily driven by an increase in wind PTCs ~~and an increase in plant regulatory differences.~~due to additional facilities going into service. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. ~~The ETR~~Impact of PTCs was ~~(4.7%) for the second quarter of 2020 compared with 9.2% for the same period in 2019.~~

~~Income taxes decreased $68 million for the first six months of 2020. Decrease was primarily driven~~partially offset by ~~an increase in wind PTCs, lower~~higher pretax earnings ~~and an increase~~ in plant-related regulatory differences. Wind PTCs are credited to customers and do not have a material impact on net income. The ETR was (3.4%) for the first six months ending June 30, 2020 compared with 8.1% for the same period in 2019.2021.

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Other

Winter Storm Uri

In February 2021, the central portion of 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.

As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $985 million (largely deferred as regulatory assets) in the first quarter. Certain energy transactions are subject to final/settlement calculation adjustments, including the impacts of credit losses shared among market participants.

Total incurred costs (net) 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 as compared to a baseline.

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

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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.


Public Utility Regulation

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. ~~The~~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 ~~rates charged to customers of Xcel Energy Inc.’s utility subsidiaries~~distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and ~~WGI are approved by the FERC or the regulatory commissions in the states in which they operate.~~Texas.

~~The rates~~Rates are designed to recover plant investment, operating costs and an allowed return on investment. ~~Xcel Energy Inc.’s~~Our utility subsidiaries request changes in utility rates ~~for utility services~~ through ~~filings with governing commissions.~~

commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate ~~case filings~~cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM 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, ~~2019~~2020 and in Item 2 of Xcel Energy’s Quarterly Report on ~~Form~~F orm 10-Q for the quarterly period ended March 31, ~~2020~~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

~~Mechanism~~

~~Utility Service~~Proceeding

Amount ~~Requested (in~~
(in millions)

Filing
Date

Approval

~~Additional Information~~

~~MPUC~~2020 North Dakota Electric Rate Case

$19

November 2020

Pending

2020 TCR Electric Rider

~~Electric~~

$82

November 2019

Pending

~~In November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.~~

~~2020~~2021 GUIC Natural Gas Rider

~~Natural Gas~~27

~~$21~~

~~November 2019~~October 2020

Pending

~~In November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain.~~

2020 RES

Electric Rider

~~$102~~107

November 2019

~~Pending~~Received

2021 RES Electric Rider

In 189

November ~~2019, NSP-Minnesota filed the~~ 2020 RES Rider with the MPUC. The requested amount includes a true-up for the 2019 rider of $38 million and the 2020 requested amount of $64 million. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.

Pending

Additional Information:

2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a rate case with the NDPSC. NSP-Minnesota requested an increase in annual retail electric revenues of approximately $19 million. The rate filing was based on a 2021 forecast test year, a ROE of 10.2%, an equity ratio of 52.5% and an electric rate base of approximately $677 million. Interim rates, subject to refund, of approximately $13 million are currently in effect.

In July 2021, NSP-Minnesota and various parties filed an uncontested settlement agreement, which includes:

•Base revenue increase of $7 million.

•ROE of 9.5%.

•Equity ratio of 52.5%.

•Deferral of advanced grid intelligence and security initiative capital and O&M expenses.

•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.

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

2020 RES Electric Rider — 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 2021, NSP-Minnesota filed a letter highlighting a change in the calculation of its total deficiency and interim rates included in its November 2020 filing. This adjustment would have reduced the filed deficiency and interim rates by approximately $43 million should the rate case have proceeded, but has no impact on the stay-out alternative petition.

In April 2021, the MPUC issued an order approving NSP-Minnesota’s proposed changes and a requirement to withdraw NSP-Minnesota’s notice of change in rates, as well as establishing a comment period allowing parties to address the changes discussed in the February letter. In June 2021, the MPUC issued an order denying a request for reconsideration of the rate case stay-out approval.

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~~NSP-Minnesota~~ —Minnesota Resource Plan — In July 2019,NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The initial plan ~~would~~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 ~~2020,~~2021, NSP-Minnesota filed an alternative plan that would reduce carbon emissions 85% by 2030 and has a ~~supplement to its resource~~lower projected cost than either of the previously submitted plans. The alternative plan ~~including new modeling scenarios required by the MPUC. The updated preferred resource plan reflects~~includes the following:

•~~Retirement of~~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 ~~the~~ early retirement of the A.S. King coal plant (511 MW) in 2028 and ~~the~~ Sherco 3 coal plant (517 MW) in ~~2030;~~2030.

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

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

•~~Construction~~Adding 3,150 MW of ~~the Sherco combined cycle natural gas plant;~~universal solar, 2,650 MW of wind and 250 MW of storage.

•~~The addition of 3,500~~Adding 800 MW of ~~solar;~~new hydrogen-ready combustion-turbines and repowering 300 MW of blackstart combustion-turbines.

•~~The addition of 2,250~~Adding 1,900 MW of ~~wind;~~other firm dispatchable resources.

•~~2,600 MW~~Constructing 155 miles of ~~firm peaking (combustion turbine, pumped hydro, battery storage, demand response etc.);~~transmission lines.

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

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

~~Initial~~Supplemental comments are due ~~Oct. 30, 2020 and reply comments are due Jan. 15,~~Aug 13, 2021. The MPUC is anticipated to make a final decision in ~~the first half of 2021.~~late 2021 or early 2022.

~~Table of Contents~~

Minnesota Relief and Recovery — In 2020, the MPUC opened a ~~Relief and Recovery~~ 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. ~~In June 2020, NSP-Minnesota filed a Relief & Recovery proposal which identified approximately $3 billion~~The status of ~~capital investment which may assist in Minnesota’s economic recovery from COVID-19. The filing included~~ the ~~following components:~~various proposals is listed below:

•AIn January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind ~~repowering solicitation that could result in 800~~projects and 20 MW of wind projects under PPAs. These projects are estimated to ~~1,000 MW with an estimated incremental investment of $1.0 to $1.4 billion;~~save customers approximately $160 million over the next 25 years.

•AIn April 2021, NSP-Minnesota proposed to add 460 MWMWs of solar ~~facility~~facilities at the Sherco site with an incremental investment of approximately ~~$650 million;~~$575 million. A MPUC decision is expected in late 2021 or early 2022.

•~~Incremental electric vehicle investment and rebates with an estimated cost of $155 million;~~In June 2021, the MPUC approved NSP-Minnesota’s proposal to acquire a 120 MW repowered wind farm from ALLETE for $210 million.

•~~Accelerated transmission investment of $180 million;~~

•~~Accelerated distribution investment of $615 million; and~~

•~~Accelerated natural gas investment of $50 million.~~

~~The MPUC scheduled a planning meeting to determine the procedural process and next steps.~~

~~NSP-Minnesota~~ — ~~Mower Wind Facility~~ —In August 2019, NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. The facility is currently contracted under a PPA with NSP-Minnesota through 2026. Mower is expected to continue to have approximately 99 MW of capacity following a planned repowering. The acquisition would occur after repowering, which is expected to be completed in 2020 and qualify for the full PTC. NSP-Minnesota will need approval from both the MPUC and FERC to complete the transaction. The MPUC is ~~expected~~also considering NSP-Minnesota’s proposal to ~~rule on the request in the third quarter~~provide $150 million of ~~2020.~~incremental electric vehicle rebates.

~~Minnesota State ROFR Statute Complaint~~ — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from Mankato to Winnebago, Minnesota. The project is estimated to cost $140 million and projected to be in-service by the end of 2021. It was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute.

The complaint challenged the constitutionality of the statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. In June 2018, the Minnesota District Court granted Minnesota state agencies and NSP-Minnesota’s motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. In February 2020, the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission’s petition for rehearing.

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, ~~2019,~~2020, for further information. The circumstances set forth in Nuclear Power Operations ~~and Waste Disposal~~ included in Item 17 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2019,~~2020, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.

NSP-Wisconsin

~~2019 Electric Fuel Cost Recovery~~ —NSP-Wisconsin Solar Proposal NSP-Wisconsin’s electric fuel costs for 2019 were lower than authorized in rates and outside the 2% annual tolerance band, primarily due to increased sales to other utilities compared to the forecast used to set authorized rates. Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately $3 million of fuel costs and defer the amount of over-recovery in excess of the 2% annual tolerance band for future refund to customers.— In ~~March 2020, NSP-Wisconsin filed with~~June 2021, the PSCW ~~indicating over-collections of~~approved NSP-Wisconsin’s request to purchase the 74 MW Western Mustang build-own-transfer solar facility for approximately ~~$10 million~~$100 million. The project is scheduled to ~~customers and proposed for refunds to be issued~~go into service in ~~September 2020.~~2023.

~~2021~~NSP-Wisconsin Electric ~~Fuel Cost Recovery~~ —and Natural Gas Settlement — In ~~June 2020,~~July 2021, NSP-Wisconsin filed an application with the PSCW ~~to update its 2021 fuel costs and return biomass fuel savings, which would decrease retail~~seeking approval of a rate case settlement with various intervenors for 2022-2023.

The settlement agreement increases electric rates by $35 million (4.9%) for ~~2021~~2022 and an incremental $18 million increase (2.5%) for 2023. For the natural gas utility, rates increase by ~~approximately $14 million. The PSCW will decide on~~$10 million (8.4%) for 2022 and an incremental $3 million (2.3%) increase for 2023.

Key elements of the ~~application later in 2020.~~

settlement include:

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

•Equity ratio of 52.5% for both 2022 and 2023.

•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 Rate Request— In July 2021, PSCo filed a request with the CPUC seeking a net increase to retail electric base rate revenue 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 is based on a 10.0% ROE, an equity ratio of 55.64% and a 2022 forecast test year. The request also includes impacts of a new depreciation study. A required test year, including a 10.5% ROE, was also filed. Rates are expected to be effective April 9, 2022.

Table of Contents

~~Mechanism~~Revenue Request (millions of dollars)

~~Utility Service~~2022

Changes since 2019 rate case:

Plant-related growth

~~Amount Requested (in millions)~~$

AGIS

Filing
Date73

Updated cost of capital

~~Approval~~53

New depreciation rates

~~Additional Information~~43

Wildfire mitigation

~~CPUC~~Property taxes

Amortization of previously approved deferrals

Other

Net increase to revenue

343

Roll-in of previously authorized costs:

TCA rider revenues and Cheyenne Ridge costs

127

Total base revenue request

470

~~Rate Case~~

~~Natural Gas~~Expected average 2022 rate base (billions of dollars)

$~~127~~

~~February 2020~~10.3

~~Pending~~

In February 2020, PSCo filed a rate case with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, partially offset by $17.7 million of costs previously authorized through the Pipeline Integrity rider. The request was based on a 9.95% ROE, an equity ratio of 55.81% and a historic test year as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020. In June 2020, PSCo revised its net increase to $121 million.

In July 2020, PSCo, the CPUC Staff and various intervenors filed a comprehensive unopposed settlement, which results in a net increase to retail gas rates of $77.3 million, reflecting a $94.1 million increase in base rate revenue, partially offset by $16.8 million of costs previously authorized through the Pipeline Integrity rider. The settlement is based on:

•~~A ROE of 9.20%;~~

•~~An equity ratio of 55.62%; and~~

•~~A historic test year as of Sept. 30, 2019, utilizing a year-end rate base, and incorporating a known and measurable adjustment for the Tungsten to Black Hawk pipeline as of April 30, 2020.~~

Rates will be implemented on April 1, 2021 and will be retroactively effective back to November 2020. In July 2020, the ALJ granted an unopposed motion to schedule a hearing for Aug. 13, 2020 to review the settlement.

~~Rate Case~~

~~Electric~~

~~$158~~

~~May 2019~~

~~Received~~

~~In 2019, PSCo filed a request with the CPUC seeking a net rate increase of $108.4 million, based on a requested ROE of 10.2% and an equity ratio of 55.6%.~~

In February 2020, the CPUC issued a written decision, resulting in an estimated $34.9 million net base rate revenue increase. The CPUC decision included a 9.3% ROE, an equity ratio of 55.61%, based on a current test year ended Aug. 31, 2019, implementation of decoupling in 2020 and other items.

In May 2020, the CPUC deliberated on PSCo’s request for rehearing and revised its prior decision on the test year calculation, return on prepaid pension and medical assets, a disallowance of a capital investment for the Comanche Unit 3 superheater and Board compensation. In July 2020, the CPUC’s written decision was received. As a result, electric rates will increase approximately $12 million, retroactive back to Feb. 25, 2020. In addition, as a part of the rehearing, the CPUC plans to discuss the merits of opening an investigation of Comanche Unit 3 performance.

~~Rate Case Appeal~~

~~Natural Gas~~

~~N/A~~

~~April 2019~~

~~Pending~~

In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology.

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. The CPUC did not appeal the decision allowing inclusion of the prepaid pension assets in rate base.

~~PSCo 2020 Rider Filings~~

2019 Electric Rate Case Appeal — In ~~July~~August 2020, PSCo filed ~~Wildfire~~an appeal with the Denver District Court seeking a review of CPUC decisions on gains and ~~Advanced Grid rider requests~~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 onthe CPUC’s decision on the Company’s Application 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 ~~instead~~for approval to terminate a solar PPA with KEPCO Solar of ~~filing a comprehensive electric rate case in 2020.~~

~~Wildfire Protection Rider— Seeks to~~Alamosa, Inc. and establish a ~~Wildfire Protection Rider~~regulatory asset to recover ~~incremental~~transaction costs ~~associated with system investments to reduce wildfire risk. The rider~~of approximately $41 million. By terminating the PPA, customers would ~~be effective no later than June~~save approximately $38 million over an 11-year period. However, the ALJ ruled against approval of the Termination Agreement. In July 2021, ~~and continue through 2025. Wildfire Protection capital additions are projected to total approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:~~

(Millions of Dollars) 2021 2022 2023 2024 2025
Forecasted annual revenue requirement $ 17 $ 24 $ 29 $ 32 $ 34

the CPUC upheld the ALJ’s recommended decision. PSCo anticipates filing an Application for Reconsideration.

~~Advanced Grid Rider~~ Electric Resource Plan — ~~Seeks~~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 ~~establish~~result in an ~~Advanced Grid Rider~~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 ~~incremental~~ costs ~~associated~~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 ~~Advanced Grid Intelligence and Security Initiative (AGIS). The rider would~~competitive solicitation for resource additions expected in Q2 2022. Incremental generation system costs to meet carbon emission reduction targets are proposed to be ~~effective no later than May 2021 and continue~~recovered through ~~2025. The~~ a Clean Energy Plan Rider.

PSCo ~~portion of the AGIS initiative is projected to total approximately $850 million of capital additions. Forecasted annual revenue requirements from 2021 through 2025 are as follows:~~

(Millions of Dollars) 2021 2022 2023 2024 2025
Forecasted annual revenue requirement $ 53 $ 69 $ 83 $ 89 $ 99

~~PSCo~~ — Comanche Unit 3

— PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. ~~PSCo is the operating agent under the joint ownership agreement.~~ In ~~June~~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, ~~during start-up~~ which damaged the plant. ~~It is currently anticipated that~~ Comanche Unit 3 ~~will recommence~~recommenced operations in ~~the fourth quarter of 2020.~~January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo ~~has obtained~~incurred replacement power ~~for a portion~~costs of approximately $16 million during the ~~unit’s output through purchase power agreements.~~

~~Boulder Municipalization~~

In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.

outage.

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~~Boulder has filed multiple separation applications with~~In October 2020, the CPUC ~~which have been challenged by PSCo~~initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance was issued in March 2021. The CPUC Staff’s report noted higher-than average outages and ~~other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects~~included some criticisms of PSCo’s ~~position.~~operations of Comanche Unit 3 over the last ten years. The ~~CPUC has approved~~report recommended thorough explanation of the ~~designation~~future of ~~some electrical distribution assets~~Comanche Unit 3 operations in the next resource plan, performance standards for ~~transfer, subject to Boulder completing certain filings.~~all company-owned generation and a review of outage and repair costs in the upcoming proceedings.

In February 2021, the ~~fourth quarter~~joint owners of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sentComanche Unit 3 (Intermountain Rural Electric Association and Holy Cross Electric) served PSCo with a notice of ~~intent~~claim related to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in September 2019 on the grounds that Boulder had not completed the pre-requisite CPUCComanche Unit 3's operation and availability. Discussions are proceeding pursuant to a contractual dispute resolution process and ~~filings. Boulder~~the amount of any alleged damages depends on multiple factors and is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding.

unknown.

In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.

In July 2020, PSCo reached a settlement with certain Boulder officials that would end the city’s effort to municipalize. The settlement, if approved, would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership, an undergrounding agreement and establish how the municipalization would move forward if Boulder exercised an opt-out. The settlement will require approval by the Boulder City Council in August 2020 and will further require approval by the citizens of Boulder in a ballot referendum in November 2020.

SPS

Pending and Recently Concluded Regulatory Proceedings

~~Mechanism~~

~~Utility Service~~Proceeding

Amount ~~Requested (in~~
(in millions)

Filing
Date

Approval

~~Additional Information~~

~~NMPRC~~

2021 New Mexico Electric Rate Case

~~Electric~~$88

~~$31~~January 2021

~~July 2019~~

~~Received~~

In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request was based on an ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on an ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk coal plant in 2032.
In January 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. The stipulation also includes an acceleration of depreciation on the Tolk coal plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The parties to the stipulation agreed not to oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. On May 11, 2020, the Hearing Examiner issued a Certification of Stipulation recommending approval of the uncontested comprehensive stipulation without modification. On May 20, 2020, the NMPRC approved the stipulation without modification. New rates and tariffs were effective beginning May 28, 2020.Pending

~~PUCT~~

2021 Texas Electric Rate Case

~~Electric~~$143

~~$141~~

~~August 2019~~February 2021

Pending

In August 2019, SPS filed an electric rate case with the PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, rate base of approximately $2.6 billion and utilizes a historic 12 month period that ended June 30, 2019. SPS’ request was subsequently revised in March 2020 to approximately $130 million, based on a requested ROE of 10.1%, a 54.62% equity ratio, rate base of approximately $2.6 billion and historic test year ended June 30, 2019.

~~On May 20, 2020, SPS, the PUCT Staff and various intervenors reached an uncontested settlement, which includes:~~

•~~An electric rate increase of $88 million and a reset of the Transmission Cost Recovery Factor to zero;~~

•~~ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes;~~

•~~Depreciation rates:~~

◦~~Tolk - 2037 end-of-life date;~~

◦~~Hale - 25-year end-of-life date;~~

◦~~All other generating units - end-of-life dates as proposed by SPS; and~~

◦~~Transmission - 35% of the incremental change between existing depreciation rates and rates proposed by SPS.~~

•~~Ring-fencing measures like those in other recent PUCT settlements, including:~~

◦~~Credit agreements and indentures (e.g., no cross-default provisions);~~

◦~~Financial covenants;~~

◦~~Restrictions on pledging of assets and securing debt;~~

◦~~Maintaining stand-alone credit facility and ratings; and~~

◦~~Affiliate and non-affiliate limitations.~~

~~Final rates are expected to be retroactively applied as of Sept. 12, 2019. A decision from the PUCT is anticipated in the third quarter of 2020.~~

Additional Information:

~~Table of Contents~~

~~Texas State ROFR Litigation~~ 2021 New Mexico Electric Rate Case — In May 2019, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. In February 2020, the federal court complaint was dismissed by the district court. In March 2020, the district court ruling was appealed to the United States Court of Appeals for the Fifth Circuit. The parties are awaiting a decision.

~~Texas Fuel Refund~~ —Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of SPS’ rates. The PUCT rule requires refunding or surcharging of under and over-recovered amounts, including interest, when they exceed 4% of the utility’s annual fuel costs.

SPS’ 2019 total fuel and purchased power costs were over-collected by approximately $39 million. As a result, SPS filed a request with the PUCT to refund the amount to customers. In April 2020, interim rates were granted by a Texas ALJ. This case is pending final review and approval by the PUCT.

~~New Mexico FPPCAC Continuation~~ ~~— In October 2019,~~January 2021, SPS filed an ~~application to~~electric rate case with the NMPRC seeking an increase in base rates of approximately $88 million. SPS' net rate increase to ~~approve SPS’ continued use~~New Mexico customers is expected to be approximately $48 million, or 10%, as 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 ~~FPPCAC~~requested base rate increase to $84 million.

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

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

•Base rate revenue increase of $62 million.

•ROE of 9.35% for purposes of filings related to (1) the Hale and Sagamore wind projects; and (2) reconciliation of ~~fuel costs for~~ the period Sept. 1, 2015, through June 30, 2019, which will determine whether all fuel costs incurred are eligible for recovery. SPS also proposed that it annually review its average New Mexico Deferred Fuelsettlement 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 ~~Purchased Power balance and requests~~coal handling assets at the ~~NMPRC approve an Annual Deferred Fuel Balance True-Up. The proposed true-up is designed~~Harrington facility to ~~maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel and purchased power costs.~~ 2024.

A public hearing is scheduled for July 26 - Aug. 6, 2021. A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.

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 million. SPS' net rate increase to ~~begin~~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 is based on a ROE of 10.35%, an equity ratio of 54.60%, a rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020.

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

Procedural schedule expected to be as follows:

•Intervenor testimony — Aug. 13, 2021.

•Staff testimony — Aug. 20, ~~2020.~~2021.

•Rebuttal testimony — Sept. 15, 2021.

•Public hearing — Oct. 18 - Oct. 28, 2021.

The PUCT set current rates as temporary as of 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. A PUCT decision is expected in the first quarter of 2022.

New Mexico Integrated Resource Plan — 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 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, and purchased power agreements. SPS will continue to evaluate other options including energy storage and emerging technologies, taking into consideration cost-effectiveness. The IRP is subject to public comment and potential public hearings and will ultimately be reviewed by the NMPRC for approval.

Environmental

~~Environmental Regulation~~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. ~~The state plans, due to~~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 ~~in July 2022, will evaluate and potentially~~to proceed with alternate regulation of coal-fired power plants. If the new rules require ~~heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect our existing coal plants, but they could require substantial~~ additional investment, ~~even in plants slated for retirement.~~ Xcel Energy believes, based on prior state commission ~~practice,~~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, 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.

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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.

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 itus 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 ~~its~~our risk management committee.

Fair value of net commodity trading contracts as of June 30, ~~2020:~~2021:


		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)		$	—	$	—	$	3	$	3	$	6	NSP-Minnesota (a)	$	(7)	$	(2)	$	1	$	1	$	(7)
NSP-Minnesota ^(b)			—		(2)		(4)		(5)		(11)

NSP- Minnesota (b)													NSP- Minnesota (b)	2		4		(10)		—		(4)
PSCo (a)													PSCo (a)	4		3		—		—		7
PSCo ^(b)	PSCo ^(b)		(1)		(40)		(15)		—		(56)		PSCo (b)	(35)		(60)		(1)		—		(96)
			$	(1)	$	(42)	$	(16)	$	(2)	$	(61)		$	(36)	$	(55)	$	(10)	$	1	$	(100)


		Options Maturity																						Options Maturity
(Millions of Dollars)	(Millions of Dollars)		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota ^(b)	NSP-Minnesota ^(b)		$	—	$	3	$	—	$	—	$	3	NSP-Minnesota (b)	$	—	$	—	$	—	$	4	$	4
PSCo ^(b)	PSCo ^(b)		—		(1)		—		—		(1)		PSCo (b)	22		39		—		—		61
			$	—	$	2	$	—	$	—	$	2		$	22	$	39	$	—	$	4	$	65

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

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

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

(Millions of Dollars) 2020 2019
Fair value of commodity trading net contract (liabilities) assets outstanding at Jan. 1 $ (59) $ 17
Contracts realized or settled during the period (7) (8)
Commodity trading contract additions and changes during the period 7 7
Fair value of commodity trading net contract (liabilities) assets outstanding at June 30 $ (59) $ 16


(Millions of Dollars)	2021		2020
Fair value of commodity trading net contracts outstanding at Jan. 1	$	(54)	$	(59)
Contracts realized or settled during the period	(37)		(7)
Commodity trading contract additions and changes during the period	56		7
Fair value of commodity trading net contracts outstanding at June 30	$	(35)	$	(59)

At June 30,

~~Table of Contents~~

2021, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately $19 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $19 million. At June 30, 2020, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $12 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $12 million. ~~At June 30, 2019, a~~Market price movements can exceed 10% increase in market prices for commodity trading contracts would decrease pre-tax income from continuing operations by approximately $2 million, whereas a 10% decrease would increase pre-tax income from continuing operations by approximately $2 million.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 ~~Value at Risk (VaR).~~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 June 30		VaR Limit		Average		High		Low
2021												2021	$	1.7	$	3.0	$	1.2	$	1.9	$	0.7
2020	2020	$	0.8	$	3.0	$	0.9	$	1.1	$	0.6	2020	0.8		3.0		0.9		1.1		0.6
2019		1.1		3.0		0.9		1.3		0.7

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 ~~51% of~~23% of its ~~2020~~2021 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impact the supply of enriched nuclear material supplied from Russia. Long-term, through 2030, NSP-Minnesota is scheduled to take delivery of approximately 30% of its average enriched nuclear material requirements from these sources. ~~Alternate potential sources provide the flexibility~~NSP-Minnesota is able to manage ~~NSP-Minnesota’s~~ nuclear fuel ~~supply.~~supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.

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, ~~2020~~2021 and ~~2019,~~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 million and $14 million, ~~and $17 million,~~ respectively.

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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 purpose of decommissioning NSP-Minnesota’s nuclear generating plants.

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

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

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

At June 30, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $64 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $24 million. At June 30, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $2 million. At June 30, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $14 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $16 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, ~~2020.~~2021.

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, ~~2020.~~

2021.

~~Table of Contents~~


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Six Months Ended June 30
(Millions of Dollars) 2020 2019
Cash provided by operating activities $ 1,148 $ 1,334
Operating Cash Flows


(Millions of Dollars)	Six Months Ended June 30
Cash provided by operating activities — 2020	$	1,148

Components of change — 2021 vs. 2020
Higher net income	91
Non-cash transactions (a)	18
Changes in working capital (b)	(35)
Changes in net regulatory and other assets and liabilities	(733)
Cash provided by operating activities — 2021	$	489

(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 ~~$186~~$659 million for the six months ended June 30, ~~2020~~2021 compared with the prior year. Decrease ~~(excluding amounts related to non-cash operating activities (e.g., depreciation and amortization and deferred tax expenses)~~ was primarily due to ~~lower collections on accounts receivable as a result~~the deferral of net natural gas, fuel and purchased energy costs related to Winter Storm Uri in the ~~COVID-19 pandemic and reduced O&M expenditures.~~first quarter.

Six Months Ended June 30
(Millions of Dollars) 2020 2019
Cash used in investing activities $ (2,580) $ (1,708)
Investing Cash Flows


(Millions of Dollars)	Six Months Ended June 30
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)

Net cash used in investing activities ~~increased $872~~decreased $378 million for the six months ended June 30, ~~2020~~2021 compared with the prior year. ~~Increase was driven by~~The decrease in capital expenditures ~~(primarily for wind projects) as well as~~was due to the purchase of MEC in January 2020, which was subsequently sold in July 2020.

Six Months Ended June 30
(Millions of Dollars) 2020 2019
Cash provided by financing activities $ 2,818 $ 580
Financing Cash Flows


(Millions of Dollars)	Six Months Ended June 30
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

Net cash provided by financing activities ~~increased $2,238~~decreased $696 million for the six months ended June 30, ~~2020~~2021 compared with the prior year. ~~Increase~~The decrease was primarily attributable to ~~proceeds from issuances~~the timing of short-term and long-term ~~debt.~~debt issuances.

Table of Contents

Capital Requirements

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

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

•In January ~~2020,~~2021, contributions of ~~$150~~$125 million were made across four of Xcel Energy’s pension plans.

•In ~~2019,~~2020, contributions of ~~$154~~$150 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 ~~27, 2020, Xcel~~26 2021, 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	$	76	$	1,174	$	621	$	1,795	Xcel Energy Inc.	$	1,250	$	508	$	742	$	—	$	742
PSCo	PSCo	700		8		692		9		701		PSCo	700		9		691		3		694
NSP-Minnesota	NSP-Minnesota	500		10		490		682		1,172		NSP-Minnesota	500		9		491		226		717
SPS	SPS	500		2		498		186		684		SPS	500		13		487		2		489
NSP-Wisconsin	NSP-Wisconsin	150		—		150		10		160		NSP-Wisconsin	150		—		150		2		152
Total	Total	$	3,100	$	96	$	3,004	$	1,508	$	4,512	Total	$	3,100	$	539	$	2,561	$	233	$	2,794

^(a)Credit facilities expire in June 2024.

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

Bilateral Credit Agreement

In ~~March 2019, NSP-Minnesota entered into a one-year~~April 2021, the uncommitted bilateral credit ~~agreement.~~agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. ~~In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one-year term.~~

As of June 30, ~~2020,~~2021, NSP-Minnesota’s outstanding letters of credit under the 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	$	31	$	44	NSP-Minnesota	$	75	$	75	$	—

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;~~PSCo.

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

•$500 million for ~~SPS; and~~SPS.

•$150 million for NSP-Wisconsin.

In addition, in ~~December 2019,~~February 2021, Xcel Energy Inc. entered into a ~~$500 million~~$1.2 billion 364-Day Term Loan Agreement that matures ~~Dec. 1, 2020.~~Feb. 17, 2022. Xcel Energy has an option to ~~request an extension~~extend through Nov. 30, 2021. In March 2020, Xcel Energy Inc. entered into a $700 million, 364-Day Term Loan Agreement that matures March 22, 2021. Xcel Energy has an option to request an extension through March 21, 2022.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, 2020			Year Ended Dec. 31, 2019			(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2021			Year Ended Dec. 31, 2020
Borrowing limit	Borrowing limit	$	4,300		$	3,600		Borrowing limit	$	4,300		$	3,100
Amount outstanding at period end	Amount outstanding at period end	1,410			595			Amount outstanding at period end	1,745			584
Average amount outstanding	Average amount outstanding	1,496			1,115			Average amount outstanding	1,521			1,126
Maximum amount outstanding	Maximum amount outstanding	1,770			1,780			Maximum amount outstanding	1,745			2,080
Weighted average interest rate, computed on a daily basis	Weighted average interest rate, computed on a daily basis	1.65		%	2.72		%	Weighted average interest rate, computed on a daily basis	0.66		%	1.45		%
Weighted average interest rate at period end	Weighted average interest rate at period end	0.76			2.34			Weighted average interest rate at period end	0.58			0.23

~~Table of Contents~~

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. 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. ~~NSP-Wisconsin currently does not participate in the money pool, however, in July 2020, an application to participate was filed.~~

~~2020~~2021 Planned Financing Activity — During ~~2020,~~2021, Xcel Energy plans to issue ~~approximately~~approximately $75 to $80 million ofof equity through the DRIP and benefit programs. ~~In addition,~~ Xcel Energy Inc. and its utility subsidiaries issued or anticipate issuing the ~~following debt securities:~~following.

Issuer Security Amount Status Tenor Coupon
Xcel Energy Inc. Senior Unsecured Notes $ 600 million Completed 10 Year 3.40 %
PSCo First Mortgage Bonds 375 million Completed 31 Year 2.70
PSCo First Mortgage Bonds 375 million Completed 11 Year 1.90
SPS First Mortgage Bonds 350 million Completed 30 Year 3.15
NSP-Wisconsin First Mortgage Bonds 100 million Completed 31 Year 3.05
NSP-Minnesota First Mortgage Bonds 700 million Completed 31 Year 2.60

~~Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.~~

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

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

In ~~November 2019~~addition, Xcel Energy ~~Inc. entered into forward equity agreements~~may issue a holding company bond in ~~connection with a completed $743 million public offering of 11.8 million shares of common stock.~~the fourth quarter to pay down the outstanding term loan.

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 ~~2020~~2021 Earnings Guidance — Xcel ~~Energy reaffirms 2020 EPS~~Energy’s 2021 GAAP and ongoing earnings guidance is a range of ~~$2.73~~$2.90 to ~~$2.83~~$3.00 per ~~share~~ share.^{(a) (b)}, which assumes the implementation of contingency plans will be sufficient to offset the negative impacts of COVID-19 under the base case scenario. However, these contingency plans would not be sufficient to offset the negative impacts of COVID-19 under the severe scenario, which would likely result in earnings below the guidance range.

Key assumptions as compared with ~~2019~~2020 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 ~~decline ~4%, under the base case scenario.~~increase ~1%.

•Weather-normalized retail firm natural gas sales are projected to ~~decline~~increase ~1%~~, under the base case scenario.~~.

•Capital rider revenue is projected to increase ~~$40~~$100 million to ~~$45~~$110 million (net of PTCs). PTCs are credited to customers, through capital riders, fuel clause or base rates and ~~reductions~~results in a reduction to electric margin.

•O&M expenses are projected to ~~decline approximately 4%~~increase 0% to ~~5% under the base case scenario.~~1%.

•Depreciation expense is projected to increase approximately ~~$180~~$155 million to ~~$190 million, reflecting updated depreciation rates in regulatory proceedings which are offset by revenue increases.~~$165 million.

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

•Interest expense (net of AFUDC - debt) is projected to increase ~~$45~~$20 million to ~~$55~~$30 million.

•AFUDC - equity is projected to ~~increase~~decline approximately ~~$35~~$40 million to ~~$45~~$50 million.

•~~The~~ ETR is projected to be ~~~0%~~(7%) to (8%). The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.

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

^(b)The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. The ultimate severity of this event is uncertain and could have a material impact on our liquidity, financial condition, or results of operations.

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 ~~2019~~2020 base of ~~$2.60~~$2.78 per share, which represents the mid-point of the original ~~2019~~2020 guidance range of ~~$2.55~~$2.73 to ~~$2.65~~$2.83 per ~~share;~~share.

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

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

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


~~COVID-19~~

Although COVID-19 represents an unprecedented event that has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will allow us to proactively manage and successfully navigate the challenges, risks and uncertainties associated with the pandemic. In addition, we have implemented O&M contingency plans to reduce costs and seek regulatory deferral mechanisms to offset the negative impact of COVID-19 on sales, bad debt and other aspects of our business.

~~Table of Contents~~

A high degree of uncertainty exists regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of recovery of the economy. Also, while we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19. The ultimate impact of this pandemic could have a material impact on Xcel Energy’s operations, financial results and cash flow.

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

~~Sales~~ — In the first half of 2020, Xcel Energy experienced a decline in weather and leap year adjusted sales. The decline in sales was primarily due to pandemic related mandates implemented in March 2020 involving the closure of non-essential businesses and state directives for individuals to stay-at-home. The stay-at-home directives and business closures moderated in May 2020.

Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand small C&I electric classes), which mitigate the impact of changes to sales levels as compared to a base line.

The following scenarios outline the potential impact of the pandemic on electric and natural gas sales and EPS, based on various assumptions of the duration of the stay-at-home provisions and economic recovery:

•~~Mild Scenario~~ ~~(severe impact through May with a V-shaped economic recovery).~~

◦~~Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of ~4% in C&I sales; and a decline in total retail electric sales of ~2%.~~

◦~~Impact on 2020 natural gas sales: ~0%.~~

◦~~This sales decline would reduce EPS by approximately $0.11.~~

•~~Base Case Scenario~~ ~~(severe impact through the second quarter with slower U-shaped recovery with lingering effects).~~

◦~~Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of 6% in C&I sales; and a decline in total retail electric sales of ~4%.~~

◦~~Impact on 2020 natural gas sales: a decline of ~1%.~~

◦~~This sales decline would reduce EPS by approximately $0.17.~~

•~~Severe Scenario~~ ~~(severe impact through the third quarter followed by protracted challenged L-shaped recovery).~~

◦~~Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of ~12% in C&I sales; and a decline in total retail electric sales of ~8%.~~

◦~~Impact on 2020 natural gas sales: a decline of ~2%.~~

◦~~This sales decline would reduce EPS by approximately $0.37.~~

•~~Potential impacts due to other items could have negative EPS impact of $0.02 to $0.05, assuming constructive regulatory treatment.~~

~~The estimated impact on our monthly weather-adjusted electric sales in the second quarter (primarily COVID-19) is as follows:~~

Month Residential C&I Total Electric Sales
April 3.2% (13.7)% (9.6)%
May 5.1 (10.6) (6.7)
June 8.9 (10.0) (4.7)

Xcel Energy incorporated the base case scenario into our 2020 guidance assumptions. The second quarter sales results came in better than anticipated in our base case scenario, however there still is substantial uncertainty on the adverse impact of COVID-19 for the remainder of the year.

~~Bad Debt~~ — In March 2020, Xcel Energy announced it would not disconnect residential customers’ electric or natural gas service during the virus outbreak. Certain states have issued additional limitations on charging late fees and extended protection to other customer classes. Bad debt expense could significantly increase due to regulatory orders, pandemic related economic impacts and customers hardship.

~~However, several of our commissions are allowing the deferral of incremental COVID-19 related expense, including bad debt expense as discussed further under Regulatory.~~

~~Regulatory~~— Xcel Energy has received orders in Minnesota, Wisconsin, Texas, New Mexico and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Costs include, but are not limited to, bad debt expense, suspension of disconnections, waived late fees and other costs and/or foregone revenues.

Xcel Energy has also filed requests in North Dakota and South Dakota to record a regulatory asset and defer all incremental expenses related to the pandemic. In July 2020, PSCo reached an agreement with Staff and the Office of Consumer Counsel on the deferral of COVID-19 related bad debt expense. These requests are pending regulatory approval.

~~Xcel Energy serves the majority of its wholesale customers under formula transmission and production rates which true-up rates to actual costs to serve.~~

Xcel Energy deferred approximately $3 million of related expenses as of June 30, 2020. We will continue to monitor these costs and assess whether the actions of the regulator provide the evidence necessary to defer amounts as regulatory assets.

~~Contingency Plan~~ — Xcel Energy has implemented contingency plans to reduce costs to offset the negative impact of COVID-19. Actions include reductions of employee expenses, consulting, variable compensation, delays of certain work activities, attrition and implementation of a hiring freeze. Based on these actions, our base case assumption is that 2020 O&M expenses will decline 4% to 5% compared with 2019. The ultimate level of O&M expenses will be dependent on actual sales levels.

We believe we can deliver earnings within our 2020 guidance range based on implementing contingency plans to offset the impact of the pandemic on sales and expense levels under the base case scenario. However, our contingency plans may not be able to offset the negative impact of COVID-19 under a severe scenario.

~~Supply Chain and Capital Expenditures~~ — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and maintain our capital expenditure program are dependent on maintaining an efficient supply chain. During the first half of 2020, Xcel Energy did not experience any material supply chain, contractor or employee disruptions that prevented us from performing maintenance or construction activity. As a result, we have not significantly adjusted our 2020 capital expenditure plan.

However, in April 2020, we were informed of supply chain disruptions, which will likely result in delays in the completion of two of our wind farms into 2021. In May 2020, the U.S. Treasury provided a one-year extension of the continuity PTC safe harbor for renewable projects, including wind and solar, that began construction in 2016 or 2017. Thus, we believe these wind farms will meet the IRS continuity requirements if ultimately placed in service in 2021. As a result, we expect these wind projects will qualify for 100% PTC benefit.

~~Table of Contents~~

~~Pension~~ — The funded status of the Xcel Energy pension plans was approximately 90% in January 2020. The funded status of the pension plan is estimated to be approximately 83%, based on market conditions as of June 2020.

Xcel Energy does not expect any material changes to its pension funding requirement at this time. In addition, Xcel Energy has pension trackers in Colorado and Texas, which allow us to defer amounts that are above or below a baseline.

~~Liquidity~~ — Xcel Energy has taken steps to enhance its liquidity and believes it has more than adequate liquidity. We have completed our debt issuance plans for Xcel Energy and its operating companies for 2020. In July 2020, we completed the sale of the MEC facility which provided an additional $650 million of funds. As a result of these actions, Xcel Energy had approximately $4.5 billion of available liquidity as of July 27, 2020.

Furthermore, Xcel Energy has an outstanding forward equity agreement in connection with a $743 million public offering of 11.8 million shares. These shares have not been issued and we expect to settle this equity forward later in 2020, which will further enhance liquidity. Finally, Xcel Energy continues to have access to the capital markets on favorable terms.

~~Customer Service & Reliability~~ — Xcel Energy remains committed to continuing to safely deliver reliable services to our customers as families and communities face the COVID-19 pandemic. We have exercised our business continuity plans to safely serve our customers, protect our employees and ensure critical positions remain staffed.

~~Key actions include:~~

•~~Executing work-from-home practices for employees who can do their work remotely;~~

•~~Enhancing cleaning practices within our facilities;~~

•~~Providing proper personal protective equipment and following CDC and state guidelines;~~

•~~Conducting employee temperature checks;~~

•~~Changing work practices to promote social distancing;~~

•~~Splitting crews and staggering work times;~~

•~~Limiting employee entry into customer homes to emergency situations only; and~~

•~~Reminding customers of increased risks of scam activity.~~

~~Employees~~ ~~— The health and safety of our workforce is one of our core values and we have taken several actions that reflect that during this pandemic:~~

•~~Continued pay for employees who have been quarantined and provide training to employees on how to stay safe and social distance;~~

•~~Expanded medical plan coverage for employees and their families to include 100% of COVID-19 medical costs;~~

•~~Offered up to an additional 80 hours of paid time off to employees for pandemic related illness;~~

•~~Expanded eligibility for our paid time off donation program to employees who have or are caring for a family member who has been diagnosed with the virus;~~

•~~Offered new anxiety and stress management tools, in addition to our existing Employee Assistance Program;~~

•~~Provided resources and educational materials to support employees adjusting to distance learning with their children; and~~

•~~Implemented an employee part-time and voluntary leave of absence program for pandemic-related needs.~~

~~Communities~~ ~~— Xcel Energy is committed to the communities in which we operate. Actions include the following:~~

•~~Plan to donate approximately $20 million in corporate giving, including COVID-19 relief in 2020.~~

•Donated over 300,000 masks to hospitals in the communities we serve; and launched a special $300,000 COVID-19 two-to-one matching campaign, which provides a match for employee donations to impacted non-profit organizations, in addition to our standard employee matching gift programs;

•~~Donating over 2.5 million high efficiency light bulbs;~~

•Submitted a proposal to reduce our approved 2020 Fuel Forecast by $25 million to provide immediate relief to our Minnesota customers, which will be implemented across the three summer months equally. Additionally, we proposed temporary relief to certain businesses in Minnesota through the Business Incentive and Sustainability Rider (approximately $6 million); and

•~~See Public Utility Regulation - NSP-Minnesota above for discussion of the Minnesota Relief and Recovery filing.~~


ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes ~~from Derivatives,~~to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2020 under “Derivatives, Risk Management and Market ~~Risk from our 2019~~ ~~Form 10-K~~.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, ~~2020,~~2021, 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 ~~the~~ procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION


ITEM 1 — LEGAL PROCEEDINGS

~~Table of Contents~~

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. ~~Unless otherwise required by GAAP, legal~~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

~~There have been no material changes from the risk factors disclosed in our~~ ~~Form 10-K~~ ~~for the year ended Dec. 31, 2019 except as follows:~~

~~We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.~~

The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.

We cannot ultimately predict whether it will have a material impact on our liquidity, financial condition, or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic.

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, ~~2019,~~2020, which is incorporated herein by ~~reference, as well as other information set forth~~reference. There have been no material changes from the risk factors previously disclosed in ~~this report, which could have a material impact on our financial condition, results of operations and cash flows.~~the Form 10-K.


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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

For the quarter ended June 30, ~~2020,~~2021, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.

Table of Contents


ITEM 6 — EXHIBITS

* Indicates incorporation by reference

~~+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors~~

Exhibit Number

Description

Report or Registration Statement

~~SEC File or Registration Number~~

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

~~001-03034~~

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

~~001-03034~~

3.01

~~4.01~~*

Supplemental Indenture No. 13, dated as of April 1, 2020 by and between Xcel Energy Inc. and Wells Fargo Bank, National Association as Trustee, creating $600 million principal amount of 3.40% Senior Notes, Series due 2030

~~Xcel Energy Inc. Form 8-K dated April 1, 2020~~

~~001-03034~~

~~4.01~~

~~4.02~~*

Supplemental Indenture dated as of May 1, 2020 between PSCo and U.S. Bank National Association, as successor Trustee, creating $375 million principal amount of 2.70% First Mortgage Bonds, Series No. 35 due 2051 and $375 million principal amount of 1.90% First Mortgage Bonds, Series No. 36 due 2031

~~PSCo Form 8-K dated May 15, 2020~~

~~001-03280~~

~~4.01~~

~~4.03~~*

~~Supplemental Indenture No. 8, dated as of May 1, 2020 between SPS and U.S. Bank National Association, as Trustee, creating $350 million principal amount of 3.15% First Mortgage Bonds, Series due 2050~~

~~SPS Form 8-K dated May 18, 2020~~

~~001-03789~~

~~4.02~~

~~4.04~~*

Supplemental Indenture dated as of May 18, 2020 between NSP-Wisconsin and U.S. Bank National Association, as Trustee, creating $100 million principal amount of 3.05% First Mortgage Bonds, Series due 2051

~~NSP-Wisconsin 8-K dated May 26, 2020~~

~~001-03140~~

~~4.01~~

~~4.05~~*

Supplemental Indenture dated as of June 8, 2020 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700 million principal amount of 2.60% First Mortgage Bonds, Series due 2051

~~NSP-Minnesota 8-K dated June 15, 2020~~

~~001-31387~~

~~4.01~~

~~10.01~~+

~~Ninth Amendment to the Xcel Energy Senior Executive Severance and Change in Control Policy~~

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

~~Certification~~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)

3635

Table of Contents

SIGNATURES

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


		XCEL ENERGY INC.

July ~~31, 2020~~29, 2021	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
		(Principal Financial Officer)

3736


	Three Months Ended June 30, 2019
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	624	$	182	$	10	$	816
C&I	1,201		90		6		1,297
Other	31		—		1		32
Total retail	1,856		272		17		2,145
Wholesale	154		—		—		154
Transmission	127		—		—		127
Other	11		26		—		37
Total revenue from contracts with customers	2,148		298		17		2,463
Alternative revenue and other	101		10		3		114
Total revenues	$	2,249	$	308	$	20	$	2,577


	Pre-Tax (Gains) Losses Reclassified into Income During the Period from:									Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)
Three Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate	$	2	^(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	(3)	^(b)
Electric commodity	—			(3)		^(c)	—
Total	$	—		$	(3)		$	(3)

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

Three Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	1	^(a)	$	—		$	—
Total	$	1		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	5	^(b)
Total	$	—		$	—		$	5

Six Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate	$	2	^(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	4	^(b)
Electric commodity	—			1		^(c)	—
Natural gas commodity	—			(1)		^(d)	(4)		^(d)
Total	$	—		$	—		$	—


(Millions of Dollars)	2021		2022		2023		2024		2025
Forecasted annual revenue requirement	$	17	$	24	$	29	$	32	$	34


Month	Residential	C&I	Total Electric Sales
April	3.2%	(13.7)%	(9.6)%
May	5.1	(10.6)	(6.7)
June	8.9	(10.0)	(4.7)