xel-20210630


Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime			e prime inc.
NSP-Minnesota			Northern States Power Company, a Minnesota corporation
NSP-Wisconsin			Northern States Power Company, a Wisconsin corporation
PSCo			Public Service Company of Colorado
SPS			Southwestern Public Service Company
Utility subsidiaries			NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI			West Gas Interstate
WYCO			WYCO Development, LLC
Xcel Energy			Xcel Energy Inc. and its subsidiaries


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

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

SEC			Securities and Exchange Commission


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


Other
AFUDC			Allowance for funds used during construction
ALJ			Administrative Law Judge
ASC			FASB Accounting Standards Codification
C&I			Commercial and Industrial
CCR			Coal combustion residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD			Cooling degree-days
CEO			Chief executive officer
CFO			Chief financial officer
COVID-19			Novel coronavirus
DRIP			Dividend Reinvestment and Stock Purchase Program
EIP			Energy Impact Partners
EPS			Earnings per share
ETR			Effective tax rate
FASB			Financial Accounting Standards Board
FTR			Financial transmission right
GAAP			United States generally accepted accounting principles
GE			General Electric Company
HDD			Heating degree-days
IPP			Independent power producing entity
IRP			Integrated Resource Plan
ISO			Independent System Operator
LLC			Limited liability company
LP&L			Lubbock Power and Light
MDL			Multi district litigation
MEC			Mankato Energy Center
MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator, Inc.
NAV			Net asset value
NOL			Net operating loss
NOPR			Notice of Proposed Rulemaking
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
PFAS			Per- and PolyFluoroAlkyl Substances


PPA			Power purchase agreement
PTC			Production tax credit
ROE			Return on equity
RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.
THI			Temperature-humidity index
TOs			Transmission owners
VaR			Value at Risk
VIE			Variable interest entity


Measurements
MW			Megawatts


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2021 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impacts 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 filings with the SEC (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020, and subsequent 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; 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.


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

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

Operating income	438		422		945		877

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

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

Income before income taxes	273		274		613		563
Income tax benefit	(38)		(13)		(60)		(19)
Net income	$	311	$	287	$	673	$	582

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

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

See Notes to Consolidated Financial Statements


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

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

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

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

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

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(390)	$	(364)
Cash paid for income taxes, net	(5)		(10)

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	509	$	436
Inventory transfers to property, plant and equipment	43		194
Operating lease right-of-use assets	1		8
Allowance for equity funds used during construction	32		61
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.

See Notes to Consolidated Financial Statements


	June 30, 2021		Dec. 31, 2020
Assets
Current assets
Cash and cash equivalents	$	538	$	129
Accounts receivable, net	948		916
Accrued unbilled revenues	699		714
Inventories	500		535
Regulatory assets	1,041		640
Derivative instruments	148		49
Prepaid taxes	52		42
Prepayments and other	221		250
Total current assets	4,147		3,275

Property, plant and equipment, net	44,141		42,950

Other assets
Nuclear decommissioning fund and other investments	3,389		3,096
Regulatory assets	3,225		2,737
Derivative instruments	92		30
Operating lease right-of-use assets	1,390		1,490
Other	395		379
Total other assets	8,491		7,732
Total assets	$	56,779	$	53,957

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	21	$	421
Short-term debt	1,745		584
Accounts payable	1,273		1,237
Regulatory liabilities	336		311
Taxes accrued	428		578
Accrued interest	207		203
Dividends payable	246		231
Derivative instruments	65		53
Operating lease liabilities	220		214
Other	409		407
Total current liabilities	4,950		4,239

Deferred credits and other liabilities
Deferred income taxes	4,807		4,746

Regulatory liabilities	5,387		5,302
Asset retirement obligations	3,059		2,884
Derivative instruments	147		131
Customer advances	196		197
Pension and employee benefit obligations	521		666
Operating lease liabilities	1,236		1,344
Other	208		228
Total deferred credits and other liabilities	15,561		15,498

Commitments and contingencies
Capitalization
Long-term debt	21,476		19,645
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 538,305,927 and 537,438,394 shares outstanding at June 30, 2021 and Dec. 31, 2020, respectively	1,346		1,344
Additional paid in capital	7,435		7,404
Retained earnings	6,146		5,968
Accumulated other comprehensive loss	(135)		(141)
Total common stockholders’ equity	14,792		14,575
Total liabilities and equity	$	56,779	$	53,957

See Notes to Consolidated Financial Statements


	Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
	Shares	Par Value		Additional Paid In Capital
Three Months Ended June 30, 2021 and 2020
Balance at March 31, 2020	525,033,594	$	1,313	$	6,659	$	5,478	$	(148)	$	13,302
Net income						287				287
Other comprehensive income								3		3
Dividends declared on common stock ($0.43 per share)						(226)				(226)
Issuances of common stock	171,384	—		11						11
Share-based compensation				9		(1)				8
Balance at June 30, 2020	525,204,978	$	1,313	$	6,679	$	5,538	$	(145)	$	13,385

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

Share-based compensation				10		(1)				9
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
Six Months Ended June 30, 2021 and 2020
Balance at Dec. 31, 2019	524,539,000	$	1,311	$	6,656	$	5,413	$	(141)	$	13,239
Net income						582				582
Other comprehensive loss								(4)		(4)
Dividends declared on common stock ($0.86 per share)						(453)				(453)
Issuances of common stock	665,978	2		21						23
Share-based compensation				2		(2)				—
Adoption of ASC Topic 326						(2)				(2)
Balance at June 30, 2020	525,204,978	$	1,313	$	6,679	$	5,538	$	(145)	$	13,385

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

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

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of June 30, 2021 and Dec. 31, 2020; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 2021 and 2020, and its cash flows for the six months ended June 30, 2021 and 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, 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, 2020 balance sheet information has been derived from the audited 2020 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 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, 2020, filed with the SEC on Feb. 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, 2020 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.

Xcel Energy implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020, 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)	June 30, 2021		Dec. 31, 2020
Accounts receivable, net
Accounts receivable	$	1,039	$	995
Less allowance for bad debts	(91)		(79)
Accounts receivable, net	$	948	$	916


(Millions of Dollars)	June 30, 2021		Dec. 31, 2020
Inventories
Materials and supplies	$	281	$	275
Fuel	166		176
Natural gas	53		84
Total inventories	$	500	$	535


(Millions of Dollars)	June 30, 2021		Dec. 31, 2020
Property, plant and equipment, net
Electric plant	$	48,861	$	47,104
Natural gas plant	7,315		7,135
Common and other property	2,524		2,503
Plant to be retired (a)	630		677
Construction work in progress	1,851		1,877
Total property, plant and equipment	61,181		59,296
Less accumulated depreciation	(17,382)		(16,657)
Nuclear fuel	3,057		2,970
Less accumulated amortization	(2,715)		(2,659)
Property, plant and equipment, net	$	44,141	$	42,950

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


4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Commercial paper and term loan borrowings outstanding for Xcel Energy:


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2021			Year Ended Dec. 31, 2020
Borrowing limit	$	4,300		$	3,100
Amount outstanding at period end	1,745			584
Average amount outstanding	1,521			1,126
Maximum amount outstanding	1,745			2,080
Weighted average interest rate, computed on a daily basis	0.66		%	1.45		%
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 obligations. At both June 30, 2021 and Dec. 31, 2020, there were $20 million of letters of credit outstanding under the credit facilities. Amounts approximate their fair value and are subject to fees.

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

As of June 30, 2021, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available
Xcel Energy Inc.	$	1,250	$	545	$	705
PSCo	700		8		692
NSP-Minnesota	500		9		491
SPS	500		2		498
NSP-Wisconsin	150		—		150
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 credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available credit facilities capacity. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of June 30, 2021 and Dec. 31, 2020.

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

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


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

Bilateral Credit Agreement

In April 2021, the uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of June 30, 2021, NSP-Minnesota’s outstanding letters of credit under the bilateral credit agreement were as follows:


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

Long-Term Borrowings and Other Financing Instruments

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

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

•SPS issued $250 million of 3.15% first mortgage bonds due 2050.

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

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


5. Revenues

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


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


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


	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		—		3		65
Total retail	3,866		954		39		4,859
Wholesale	977		—		—		977
Transmission	294		—		—		294
Other	34		61		—		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		—		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


6. Income Taxes

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

Difference between the statutory rate and ETR:


	Three Months Ended June 30				Six Months Ended June 30
	2021		2020		2021		2020
Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
State tax (net of federal tax effect)	4.9		5.1		4.9		5.0
Decreases:
Wind PTCs	(33.1)		(21.1)		(28.4)		(19.1)
Plant regulatory differences (a)	(6.6)		(7.1)		(6.3)		(7.8)
Other (net)	(0.1)		(2.6)		(1.0)		(2.5)
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
2014 — 2016						January 2022
2017						September 2021

Additionally, the statute of limitations related to a federal tax loss carryback claim filed in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

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

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


State						Year
Colorado						2009
Minnesota						2013
Texas						2012
Wisconsin						2016

•In July 2020, Minnesota began a review of tax years 2015 - 2018. In February 2021, Minnesota concluded its review and commenced an audit of the same tax years. No material adjustments have been proposed.

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

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

•No other state income tax audits were in progress as of June 30, 2021.

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

Unrecognized tax benefits — permanent vs. temporary:


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

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


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

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

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

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)	$	—
Interest expense related to unrecognized tax benefits	—		(3)
Payable for interest related to unrecognized tax benefits at end of period	$	(3)	$	(3)

No penalties were accrued related to unrecognized tax benefits as of June 30, 2021 or Dec. 31, 2020.


7. Earnings Per Share

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

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

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

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

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

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

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

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


	Three Months Ended June 30		Six Months Ended June 30
(Shares in Millions)	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 six months ended June 30, 2021 and 2020, respectively.


8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

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

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

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

Specific valuation methods include:

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

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

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

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

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

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

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

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

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

Non-Derivative Fair Value Measurements

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

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

Unrealized gains for the nuclear decommissioning fund were $1.2 billion and $981 million as of June 30, 2021 and Dec. 31, 2020, respectively, and unrealized losses were $3 million and $5 million as of June 30, 2021 and Dec. 31, 2020, respectively.

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


	June 30, 2021
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	30	$	30	$	—	$	—	$	—	$	30
Commingled funds	800		—		—		—		1,164		1,164
Debt securities	612		—		641		16		—		657
Equity securities	408		1,185		2		—		—		1,187
Total	$	1,850	$	1,215	$	643	$	16	$	1,164	$	3,038

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


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

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

For the three and six months ended June 30, 2021 and 2020, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of June 30, 2021:


	Final Contractual Maturity
(Millions of Dollars)	Due in 1 year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 years		Total
Debt securities	$	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.

Cost and fair value of assets held in rabbi trusts:


	June 30, 2021
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Rabbi Trusts (a)
Cash equivalents	$	23	$	23	$	—	$	—	$	23
Mutual funds	71		84		—		—		84
Total	$	94	$	107	$	—	$	—	$	107


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

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

Derivative Instruments Fair Value Measurements

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

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

As of June 30, 2021, accumulated other comprehensive loss related to settled interest rate derivatives included $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, 2021, Xcel Energy had no unsettled interest rate derivatives.

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

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

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

As of June 30, 2021, Xcel Energy had no commodity contracts designated as cash flow hedges.

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

Gross notional amounts of commodity forwards, options and FTRs:


(Amounts in Millions) (a)(b)	June 30, 2021	Dec. 31, 2020
Megawatt hours of electricity	122	87
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, 2021, six of Xcel Energy’s ten most significant counterparties for these activities, comprising $118 million, or 44%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Two of the ten most significant counterparties, comprising $27 million, or 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. Two of these significant counterparties, comprising $62 million or 23% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Seven of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

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	$	—	$	11
Natural gas commodity	—		(1)
Total	$	—	$	10

Six Months Ended June 30, 2021



Other derivative instruments
Electric commodity	$	—	$	13

Total	$	—	$	13


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)


	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)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	12	(b)
Electric commodity	—			3		(c)	—

Total	$	—		$	3		$	12

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

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)

(a)Recorded to interest charges.

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

(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d)Amounts for both the six months ended June 30, 2021 and 2020 included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Remaining settlement losses for both the six months ended June 30, 2021 and 2020 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.

Xcel Energy had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2021 and 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. 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 provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of June 30, 2021 and Dec. 31, 2020, there were approximately $69 million and $60 million of derivative liabilities with such underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2021 and Dec. 31, 2020.

Changes in Level 3 commodity derivatives:


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

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

(a)Presented amounts relate to 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 no transfers of amounts between levels for derivative instruments for the six months ended June 30, 2021 and 2020.

Fair Value of Long-Term Debt

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


	June 30, 2021				Dec. 31, 2020
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
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, 2021 and Dec. 31, 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
	2021		2020		2021		2020
(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	$	26	$	24	$	1	$	—
Interest cost (a)	26		31		3		5
Expected return on plan assets (a)	(51)		(52)		(5)		(5)
Amortization of prior service credit (a)	(1)		(1)		(2)		(2)
Amortization of net loss (a)	27		25		2		1
Net periodic benefit cost (credit)	27		27		(1)		(1)
Effects of regulation	—		1		—		1
Net benefit cost (credit) recognized for financial reporting	$	27	$	28	$	(1)	$	—


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

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

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


10. Commitments and Contingencies

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

Legal

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

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

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

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

Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.

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

In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate. A final decision by the MPUC is pending. A loss related to this matter is deemed remote.

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

NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. It is uncertain when a final resolution will occur, but it is unlikely an arbitration hearing will take place before the fourth quarter 2021. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined.

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

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

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

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

In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. 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.

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

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. SPS has intervened in both 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 asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. This 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 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The proposed rule would establish an annual forecast of GCA costs for each utility and allow each utility to recover only 90%-95% of any costs in excess of the forecasted amount. The proposed rule would allow utilities to earn an incentive equal to an undefined portion of any savings relative to forecasted costs. Initial comments were due July 23, 2021, reply comments are due Aug. 6, 2021 and a hearing is scheduled for Aug. 26, 2021. A CPUC decision in expected in the third quarter of 2021.

Environmental

MGP, Landfill and Disposal Sites

Xcel Energy is investigating, remediating or performing post-closure actions at 13 MGP, landfill or other disposal sites across its service territories.

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

Xcel Energy is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, increases above background concentrations were detected at four locations. Based on further assessments, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. The total cost is uncertain, but could be up to $35 million. PSCo is continuing to assess the financial and regulatory impacts.

In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. This final rule required Xcel Energy to expedite closure plans for two 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 also now proceed with closure of the pond, with an estimated cost of $3 million.

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

Leases

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

Components of lease expense:


	Three Months Ended June 30
(Millions of Dollars)	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 $1 million for 2021 and 2020, respectively.

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


	Six Months Ended June 30
(Millions of Dollars)	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.

Commitments under operating and finance leases as of June 30, 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 to Xcel Energy’s 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. These specific PPAs create a variable interest in the IPP.

The utility subsidiaries had approximately 4,062 MW of capacity under long-term PPAs at both June 30, 2021 and Dec. 31, 2020 with entities that have been determined to be VIEs. Xcel Energy concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. The PPAs have expiration dates through 2041.

Other

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the agreements. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.

As of June 30, 2021 and Dec. 31, 2020, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were approximately $60 million and $62 million at June 30, 2021 and Dec. 31, 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 duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated.

12. Segment Information

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

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

Xcel Energy has the following reportable segments:

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

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

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

Xcel Energy had equity method investments of $189 million and $165 million as of June 30, 2021 and Dec. 31, 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:


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

Electric and Natural Gas Margins

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

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

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

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

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

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, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

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

Summarized diluted EPS for Xcel Energy:


	Three Months Ended June 30				Six Months Ended June 30
Diluted Earnings (Loss) Per Share	2021		2020		2021		2020
PSCo	$	0.25	$	0.21	$	0.56	$	0.45
NSP-Minnesota	0.21		0.22		0.45		0.43
SPS	0.13		0.14		0.23		0.22
NSP-Wisconsin	0.03		0.02		0.09		0.09
Earnings from equity method investments - WYCO	0.01		0.01		0.02		0.02
Regulated utility (a)	0.62		0.60		1.35		1.20
Xcel Energy Inc. and Other	(0.04)		(0.07)		(0.10)		(0.10)
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 $0.04 per share for the second quarter of 2021 and increased $0.15 per share year-to-date. Earnings primarily reflect higher electric and natural gas margins (driven by capital investment recovery, regulatory outcomes and weather-normalized sales growth as compared to 2020, which was more adversely impacted by COVID-19). These drivers were partially offset by higher depreciation, O&M expenses, interest charges and 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 (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 electric margin (primarily capital investment recovery), partially offset by increased depreciation and O&M expenses.

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 2021 and were flat year-to-date.

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

Changes in GAAP and Ongoing Diluted EPS

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


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 plant regulatory amounts, which are primarily offset in electric margin.

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.

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

Percentage increase (decrease) in normal and actual HDD:


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

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


	Three Months Ended June 30						Six Months Ended June 30
	2021 vs. Normal		2020 vs. Normal		2021 vs. 2020		2021 vs. Normal		2020 vs. Normal		2021 vs. 2020
Retail electric	$	0.056	$	0.028	$	0.028	$	0.055	$	0.017	$	0.038
Decoupling and sales true-up	(0.044)		(0.014)		(0.030)		(0.041)		(0.009)		(0.032)
Electric total	$	0.012	$	0.014	$	(0.002)	$	0.014	$	0.008	$	0.006
Firm natural gas	0.002		0.001		0.001		0.005		(0.006)		0.011
Total	$	0.014	$	0.015	$	(0.001)	$	0.019	$	0.002	$	0.017

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


	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	—	%	6.1	%	(5.6)	%	2.7	%	1.9	%
Electric C&I	6.2		10.1		7.5		11.6		8.3
Total retail electric sales	3.9		8.7		5.2		8.9		6.3
Firm natural gas sales	18.8		(9.5)		N/A		(2.5)		8.3


	Three Months Ended June 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	0.7	%	(1.6)	%	(1.3)	%	(2.3)	%	(0.7)	%
Electric C&I	6.5		8.3		8.4		10.2		7.9
Total retail electric sales	4.4		5.0		6.8		6.5		5.3
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
Electric residential	3.2	%	5.6	%	1.8	%	3.8	%	4.0	%
Electric C&I	0.4		1.3		—		4.5		0.9
Total retail electric sales	1.4		2.7		0.3		4.3		1.8
Firm natural gas sales	8.0		(1.9)		N/A		—		4.4


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


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

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

Weather-adjusted sales results for each of our utility subsidiaries in 2021 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 an increase in the number of customers combined with higher use per customer. The growth in large C&I sales was primarily led by the service, agriculture, food and energy sectors, partially offset by a decrease in the manufacturing sector.

•NSP-Minnesota — Residential sales growth reflects an increase in the number of customers combined with higher use per customer. The growth in C&I sales was due to customer growth and slightly higher use per customer, primarily in the manufacturing 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 higher use per customer and growth attributable to the food sector, partially offset by losses within the energy sector.

•NSP-Wisconsin — Residential sales growth was attributable to customer additions and higher use per customer. The growth in C&I sales was primarily led by increases in the services, agriculture, food and 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 slightly higher customer use.

Electric Margin

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations 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, which reduce electric revenue and margin.

Electric revenues and margin:


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

Changes in electric margin:


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

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

(a)Sales excludes weather impact, net of decoupling/sales true-up, and demand 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 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
(Millions of Dollars)	2021		2020		2021		2020
Natural gas revenues	$	449	$	280	$	1,096	$	863
Cost of natural gas sold and transported	(218)		(86)		(517)		(371)
Natural gas margin	$	231	$	194	$	579	$	492

Changes in natural gas margin:


(Millions of Dollars)	Three Months Ended June 30, 2021 vs. 2020		Six Months Ended June 30, 2021 vs. 2020
Regulatory rate outcomes (Colorado)	$	31	$	71
Estimated impact of weather	1		8



Other (net)	5		8


Total increase in natural gas margin	$	37	$	87

Non-Fuel Operating Expenses and Other Items

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



(Millions of Dollars)	Three Months Ended June 30, 2021 vs. 2020		Six Months Ended June 30, 2021 vs. 2020
Wind	$	14	$	22
Information technology and security	13		17
Natural gas systems	6		9
Distribution	9		8

Other	8		(1)
Total increase in O&M expenses	$	50	$	55

The increase was primarily due to expenses 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 control initiatives to mitigate the adverse impact of COVID-19 on sales.

Depreciation and Amortization — Depreciation and amortization increased $55 million, or 11.6%, for the second quarter and $113 million or 12.1% year-to-date. The increase was primarily driven by several wind 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 in various states.

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

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

Interest Charges — Interest charges increased $4 million, or 1.9%, for the second quarter and $10 million or 2.5% year-to-date. The increase was 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 tax benefit increased $25 million for the second quarter and $41 million year-to-date. The increase was primarily driven by an increase in wind PTCs due to additional facilities going into service. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. Impact of PTCs was partially offset by higher pretax earnings in 2021.


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.

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. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas.

Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.

In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020 and in Item 2 of Xcel Energy’s Quarterly Report on F orm 10-Q for the quarterly period ended March 31, 2021 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings

Proceeding

Amount
(in millions)

Filing
Date

Approval

2020 North Dakota Electric Rate Case

$19

November 2020

Pending

2020 TCR Electric Rider

November 2019

Pending

2021 GUIC Natural Gas Rider

October 2020

Pending

2020 RES Electric Rider

107

November 2019

Received

2021 RES Electric Rider

189

November 2020

Pending

Additional Information:

2020 North Dakota 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.

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

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

•Removing the planned Sherco combined cycle natural gas plant.

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

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

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

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

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

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

•Constructing 155 miles of transmission lines.

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

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

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

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

•In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years.

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

•In June 2021, the MPUC approved NSP-Minnesota’s proposal to acquire a 120 MW repowered wind farm from ALLETE for $210 million.

•The MPUC is also considering NSP-Minnesota’s proposal to provide $150 million of incremental electric vehicle rebates.

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020, for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2020, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.

NSP-Wisconsin

NSP-Wisconsin Solar Proposal — In June 2021, the PSCW approved NSP-Wisconsin’s request to purchase the 74 MW Western Mustang build-own-transfer solar facility for approximately $100 million. The project is scheduled to go into service in 2023.

NSP-Wisconsin Electric and Natural Gas Settlement — In July 2021, NSP-Wisconsin filed an application with the PSCW 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 2022 and an incremental $18 million increase (2.5%) for 2023. For the natural gas utility, rates increase by $10 million (8.4%) for 2022 and an incremental $3 million (2.3%) increase for 2023.

Key elements of the settlement include:

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

•Equity 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.


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


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

2019 Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gains and losses on sales of assets, oil and gas royalty revenues, Board of Directors equity compensation and a true-up surcharge to collect the difference between what rates should have been in place from February through August 2020 (based on the 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 for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. However, the ALJ ruled against approval of the Termination Agreement. In July 2021, the CPUC upheld the ALJ’s recommended decision. PSCo anticipates filing an Application for Reconsideration.

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

Major components of PSCo's proposed preferred plan include:

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

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

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

•2,300 MW of wind power.

•1,600 MW of large-scale solar power.

•400 MW of energy storage.

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

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

A CPUC decision on the resource plan is expected in January of 2022 with the competitive solicitation for resource additions expected in Q2 2022. Incremental generation system costs to meet carbon emission reduction targets are proposed to be recovered through a Clean Energy Plan Rider.

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

In October 2020, the CPUC 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 included some criticisms of PSCo’s operations of Comanche Unit 3 over the last ten years. The report recommended thorough explanation of the future of Comanche Unit 3 operations in the next resource plan, performance standards for all company-owned generation and a review of outage and repair costs in the upcoming proceedings.

In February 2021, the joint owners of Comanche Unit 3 (Intermountain Rural Electric Association and Holy Cross Electric) served PSCo with a notice of claim related to Comanche Unit 3's operation and availability. Discussions are proceeding pursuant to a contractual dispute resolution process and the amount of any alleged damages depends on multiple factors and is currently unknown.

SPS

Pending and Recently Concluded Regulatory Proceedings

Proceeding

Amount
(in millions)

Filing
Date

Approval

2021 New Mexico Electric Rate Case

$88

January 2021

Pending

2021 Texas Electric Rate Case

$143

February 2021

Pending

Additional Information:

2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $88 million. SPS' net rate increase to New Mexico customers is expected to be approximately $48 million, or 10%, as 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 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 the settlement revenue requirement.

•Equity ratio of 54.72%.

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

A public hearing is scheduled for July 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, SPS filed 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 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, 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

Affordable Clean Energy

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

Emerging Regulation

New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the environment. These chemicals have received heightened attention by environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal, 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.


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 us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

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

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


	Futures / Forwards Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	$	(7)	$	(2)	$	1	$	1	$	(7)
NSP- Minnesota (b)	2		4		(10)		—		(4)
PSCo (a)	4		3		—		—		7
PSCo (b)	(35)		(60)		(1)		—		(96)
	$	(36)	$	(55)	$	(10)	$	1	$	(100)


	Options Maturity
(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	$	—	$	—	$	—	$	4	$	4
PSCo (b)	22		39		—		—		61
	$	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)	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, 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. Market price movements can exceed 10% under abnormal circumstances.

The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding contracts and obligations over a particular period of time under normal market conditions.

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


(Millions of Dollars)	Three Months Ended June 30		VaR Limit		Average		High		Low
2021	$	1.7	$	3.0	$	1.2	$	1.9	$	0.7
2020	0.8		3.0		0.9		1.1		0.6

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

Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 23% of its 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. NSP-Minnesota is able to manage nuclear fuel supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.

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, 2021 and 2020, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pre-tax interest expense annually by approximately $18 million and $14 million, respectively.

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.

Xcel Energy conducts credit reviews for all counterparties and employs credit risk control, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.


FAIR VALUE MEASUREMENTS

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

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

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

Commodity Derivatives — Xcel Energy monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at June 30, 2021.

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at June 30, 2021.


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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 $659 million for the six months ended June 30, 2021 compared with the prior year. Decrease was primarily due to the deferral of net natural gas, fuel and purchased energy costs related to Winter Storm Uri in the first quarter.

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 decreased $378 million for the six months ended June 30, 2021 compared with the prior year. The decrease in capital expenditures was due to the purchase of MEC in January 2020, which was subsequently sold in July 2020.

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 decreased $696 million for the six months ended June 30, 2021 compared with the prior year. The decrease was primarily attributable to the timing of short-term and long-term debt issuances.

Capital Requirements

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

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

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

•In 2020, contributions of $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 26 2021, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,250	$	508	$	742	$	—	$	742
PSCo	700		9		691		3		694
NSP-Minnesota	500		9		491		226		717
SPS	500		13		487		2		489
NSP-Wisconsin	150		—		150		2		152
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 April 2021, the uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of June 30, 2021, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreement were as follows:


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

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

•$1.25 billion for Xcel Energy Inc.

•$700 million for PSCo.

•$500 million for NSP-Minnesota.

•$500 million for SPS.

•$150 million for NSP-Wisconsin.

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

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


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

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.

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

Issuer

Security

Amount

Status

Tenor

Coupon

PSCo

First Mortgage Bonds

750

million

Completed

10 Year

1.875

SPS

First Mortgage Bonds

250

million

Completed

29 Year

3.15

NSP-Minnesota

First Mortgage Bonds

425

million

Completed

10 Year

2.25

NSP-Minnesota

First Mortgage Bonds

425

million

Completed

31 Year

3.20

NSP-Wisconsin

First Mortgage Bonds

100

million

Q3 (a)

30 Year

2.82

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

In addition, Xcel Energy may issue a holding company bond in 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.

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

Xcel Energy 2021 Earnings Guidance — Xcel Energy’s 2021 GAAP and ongoing earnings guidance is a range of $2.90 to $3.00 per share.(a)

Key assumptions as compared with 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 increase ~1%.

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

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

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

•Depreciation expense is projected to increase approximately $155 million to $165 million.

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

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

•AFUDC - equity is projected to decline approximately $40 million to $50 million.

•ETR is projected to be (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.

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

•Deliver long-term annual EPS growth of 5% to 7% based off of a 2020 base of $2.78 per share, which represents the mid-point of the original 2020 guidance range of $2.73 to $2.83 per share.

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

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

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


ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2020 under “Derivatives, Risk Management and Market Risk.”


ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

As of June 30, 2021, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION


ITEM 1 — LEGAL PROCEEDINGS

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

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


ITEM 1A — RISK FACTORS

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2020, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.


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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

For the quarter ended June 30, 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.


Class						Outstanding at July 22, 2021
Common Stock, $2.50 par value						538,436,651 shares


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	4
	Consolidated Statements of Income	4
	Consolidated Statements of Comprehensive Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Balance Sheets	7
	Consolidated Statements of Common Stockholders’ Equity	8
	Notes to Consolidated Financial Statements	9
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	34
Item 4 —	Controls and Procedures	34

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	34
Item 1A —	Risk Factors	34
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 6 —	Exhibits	35

SIGNATURES		36


	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 $—, $—, $1 and $—, respectively) (a)	2		—		2		1		—		1
Amortization of net actuarial loss (net of taxes of $—, $—, $— and $1, respectively ) (b)	—		1		1		—		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)


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


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


Xcel Energy Inc.
(Exact name of registrant as specified in its charter)


(612)			330-5500
(Registrant’s telephone number, including area code)


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


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012	Xcel Energy Inc. Form 8-K dated May 16, 2012	3.01
3.02*	Bylaws of Xcel Energy Inc. as Amended on April 3, 2020	Xcel Energy Inc Form 8-K dated April 3, 2020	3.01
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


		XCEL ENERGY INC.

July 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)