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


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

LES-FEA			Louisiana Energy Services & Federal Executive Agencies
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
ECA			Retail electric commodity adjustment
GCA			Gas cost ~~adjustment~~
~~GUIC~~			~~Gas utility infrastructure cost rider~~
~~PSIA~~			~~Pipeline System Integrity Adjustment~~
~~RES~~			~~Renewable energy standard~~
~~TCR~~			~~Transmission cost recovery~~ adjustment


Other
~~ACE~~			~~Affordable Clean Energy~~
AFUDC			Allowance for funds used during construction
AG			New Mexico Attorney General
ALJ			Administrative Law Judge
ATM			At-the-market
~~BART~~			~~Best available retrofit technology~~
C&I			Commercial and Industrial
CCR			Coal combustion residuals
CCR Rule			Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD			Cooling degree-days
CEO			Chief executive officer


CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFO			Chief financial officer
CORE			CORE Electric Cooperative
~~CPCN~~			~~Certificate of Public Convenience and Necessity~~
~~CPP~~			~~Clean Power Plan~~
CSPV			Crystalline Silicon Photovoltaic
~~CUB~~			~~Citizens Utility Board~~
DRIP			Dividend Reinvestment and Stock Purchase Program
EPS			Earnings per share
ETR			Effective tax rate
FTR			Financial transmission right
FTY			Future test year
GAAP			United States generally accepted accounting principles
GE			General Electric Company
HDD			Heating degree-days
IPP			Independent power producing entity
IRA			Inflation Reduction Act
LDC			Local distribution company
LLC			Limited liability company
LP&L			Lubbock Power and Light
MGP			Manufactured gas plant
MISO			Midcontinent Independent System Operator, Inc.
NAV			Net asset value
NMLCG			New Mexico Large Customer Group
NOPR			Notice of Proposed Rulemaking
NOx			Nitrogen Oxides
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
OPL			Occidental Permian Ltd.
PFAS			Per- and Polyfluroroalkyl Substances
PIM			Performance Incentive Mechanism
PPA			Power purchase agreement
PTC			Production tax credit
RFP			Request for proposal
ROE			Return on equity


RTO			Regional Transmission Organization
SMMPA			Southern Minnesota Municipal Power Agency
SPP			Southwest Power Pool, Inc.
TCA			Transmission cost adjustment
THI			Temperature-humidity index
TOs			Transmission owners
~~UCA~~			~~Colorado Office of the Utility Consumer Advocate~~
VaR			Value at Risk


Measurements
MW			Megawatts

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


		Six Months Ended June 30					Three Months Ended March 31
		2022		2021			2023		2022
Operating activities	Operating activities					Operating activities
Net income	Net income	$	708	$	673	Net income	$	418	$	380
Adjustments to reconcile net income to cash provided by operating activities:	Adjustments to reconcile net income to cash provided by operating activities:					Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	1,210		1,043		Depreciation and amortization	631		567
Nuclear fuel amortization	Nuclear fuel amortization	61		56		Nuclear fuel amortization	29		30
Deferred income taxes	Deferred income taxes	(135)		(67)		Deferred income taxes	(73)		(55)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(33)		(32)		Allowance for equity funds used during construction	(19)		(13)
Earnings from equity method investments	Earnings from equity method investments	(26)		(34)		Earnings from equity method investments	(11)		(15)
Dividends from equity method investments	Dividends from equity method investments	20		21		Dividends from equity method investments	9		10
Provision for bad debts	Provision for bad debts	30		27		Provision for bad debts	23		17
Share-based compensation expense	Share-based compensation expense	14��		21		Share-based compensation expense	9		4
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Accounts receivable	Accounts receivable	(97)		(63)		Accounts receivable	50		(191)
Accrued unbilled revenues	Accrued unbilled revenues	70		14		Accrued unbilled revenues	329		146
Inventories	Inventories	(44)		7		Inventories	189		107
Other current assets	Other current assets	26		24		Other current assets	8		(10)
Accounts payable	Accounts payable	137		(15)		Accounts payable	(359)		(34)
Net regulatory assets and liabilities	Net regulatory assets and liabilities	213		(794)		Net regulatory assets and liabilities	345		215
Other current liabilities	Other current liabilities	(134)		(265)		Other current liabilities	63		51
Pension and other employee benefit obligations	Pension and other employee benefit obligations	(32)		(128)		Pension and other employee benefit obligations	(45)		(31)
Other, net	Other, net	—		1		Other, net	(59)		(38)
Net cash provided by operating activities	Net cash provided by operating activities	1,988		489		Net cash provided by operating activities	1,537		1,140

Investing activities	Investing activities					Investing activities
Capital/construction expenditures	Capital/construction expenditures	(2,040)		(1,967)		Capital/construction expenditures	(1,265)		(942)
Purchase of investment securities	Purchase of investment securities	(787)		(628)		Purchase of investment securities	(236)		(156)
Proceeds from the sale of investment securities	Proceeds from the sale of investment securities	769		410		Proceeds from the sale of investment securities	228		147
Other, net	Other, net	3		(17)		Other, net	(11)		(1)
Net cash used in investing activities	Net cash used in investing activities	(2,055)		(2,202)		Net cash used in investing activities	(1,284)		(952)

Financing activities	Financing activities					Financing activities
(Repayments of) proceeds from short-term borrowings, net		(869)		1,161
Proceeds from issuances of long-term debt		2,066		1,821
Proceeds from (repayments of) short-term borrowings, net						Proceeds from (repayments of) short-term borrowings, net	266		(9)

Repayments of long-term debt, including reacquisition premiums	Repayments of long-term debt, including reacquisition premiums	(600)		(399)		Repayments of long-term debt, including reacquisition premiums	(250)		—
Proceeds from issuance of common stock	Proceeds from issuance of common stock	151		11		Proceeds from issuance of common stock	6		1
Dividends paid	Dividends paid	(497)		(460)		Dividends paid	(259)		(240)
Other, net	Other, net	(15)		(12)		Other, net	(13)		(16)
Net cash provided by financing activities		236		2,122
Net cash used in financing activities						Net cash used in financing activities	(250)		(264)

Net change in cash, cash equivalents and restricted cash	Net change in cash, cash equivalents and restricted cash	169		409		Net change in cash, cash equivalents and restricted cash	3		(76)
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	166		129		Cash, cash equivalents and restricted cash at beginning of period	111		166
Cash, cash equivalents and restricted cash at end of period	Cash, cash equivalents and restricted cash at end of period	$	335	$	538	Cash, cash equivalents and restricted cash at end of period	$	114	$	90

Supplemental disclosure of cash flow information:	Supplemental disclosure of cash flow information:					Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	Cash paid for interest (net of amounts capitalized)	$	(425)	$	(390)	Cash paid for interest (net of amounts capitalized)	$	(209)	$	(202)
Cash paid for income taxes, net	Cash paid for income taxes, net	(9)		(5)		Cash paid for income taxes, net	(1)		—

Supplemental disclosure of non-cash investing and financing transactions:	Supplemental disclosure of non-cash investing and financing transactions:					Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	Accrued property, plant and equipment additions	$	401	$	509	Accrued property, plant and equipment additions	$	449	$	288
Inventory transfers to property, plant and equipment	Inventory transfers to property, plant and equipment	30		43		Inventory transfers to property, plant and equipment	34		20
Operating lease right-of-use assets	Operating lease right-of-use assets	15		1		Operating lease right-of-use assets	47		8
Allowance for equity funds used during construction	Allowance for equity funds used during construction	33		32		Allowance for equity funds used during construction	19		13
Issuance of common stock for reinvested dividends and/or equity awards	Issuance of common stock for reinvested dividends and/or equity awards	27		35		Issuance of common stock for reinvested dividends and/or equity awards	21		11

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


		June 30, 2022		Dec. 31, 2021			March 31, 2023		Dec. 31, 2022
Assets	Assets					Assets
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	335	$	166	Cash and cash equivalents	$	114	$	111
Accounts receivable, net	Accounts receivable, net	1,084		1,018		Accounts receivable, net	1,300		1,373
Accrued unbilled revenues	Accrued unbilled revenues	792		862		Accrued unbilled revenues	777		1,105
Inventories	Inventories	645		631		Inventories	580		803
Regulatory assets	Regulatory assets	1,085		1,106		Regulatory assets	983		1,059
Derivative instruments	Derivative instruments	534		123		Derivative instruments	97		279
Prepaid taxes	Prepaid taxes	51		44		Prepaid taxes	43		54
Prepayments and other	Prepayments and other	316		289		Prepayments and other	359		360
Total current assets	Total current assets	4,842		4,239		Total current assets	4,253		5,144

Property, plant and equipment, net	Property, plant and equipment, net	46,535		45,457		Property, plant and equipment, net	48,896		48,253

Other assets	Other assets					Other assets
Nuclear decommissioning fund and other investments	Nuclear decommissioning fund and other investments	3,229		3,628		Nuclear decommissioning fund and other investments	3,373		3,234
Regulatory assets	Regulatory assets	2,965		2,738		Regulatory assets	2,657		2,871
Derivative instruments	Derivative instruments	105		67		Derivative instruments	97		93
Operating lease right-of-use assets	Operating lease right-of-use assets	1,202		1,291		Operating lease right-of-use assets	1,194		1,204
Other	Other	439		431		Other	475		389
Total other assets	Total other assets	7,940		8,155		Total other assets	7,796		7,791
Total assets	Total assets	$	59,317	$	57,851	Total assets	$	60,945	$	61,188

Liabilities and Equity	Liabilities and Equity					Liabilities and Equity
Current liabilities	Current liabilities					Current liabilities
Current portion of long-term debt	Current portion of long-term debt	$	651	$	601	Current portion of long-term debt	$	901	$	1,151
Short-term debt	Short-term debt	136		1,005		Short-term debt	1,079		813
Accounts payable	Accounts payable	1,590		1,409		Accounts payable	1,338		1,804
Regulatory liabilities	Regulatory liabilities	682		271		Regulatory liabilities	358		418
Taxes accrued	Taxes accrued	415		569		Taxes accrued	682		569
Accrued interest	Accrued interest	219		209		Accrued interest	242		217
Dividends payable	Dividends payable	266		249		Dividends payable	286		268
Derivative instruments	Derivative instruments	142		69		Derivative instruments	62		76
Operating lease liabilities	Operating lease liabilities	210		205		Operating lease liabilities	224		217
Other	Other	554		459		Other	489		545
Total current liabilities	Total current liabilities	4,865		5,046		Total current liabilities	5,661		6,078

Deferred credits and other liabilities	Deferred credits and other liabilities					Deferred credits and other liabilities
Deferred income taxes	Deferred income taxes	4,708		4,894		Deferred income taxes	4,729		4,756
Deferred investment tax credits	Deferred investment tax credits	51		53		Deferred investment tax credits	47		48
Regulatory liabilities	Regulatory liabilities	5,498		5,405		Regulatory liabilities	5,640		5,569
Asset retirement obligations	Asset retirement obligations	3,271		3,151		Asset retirement obligations	3,423		3,380
Derivative instruments	Derivative instruments	120		105		Derivative instruments	116		113
Customer advances	Customer advances	184		196		Customer advances	180		181
Pension and employee benefit obligations	Pension and employee benefit obligations	259		306		Pension and employee benefit obligations	345		390
Operating lease liabilities	Operating lease liabilities	1,047		1,146		Operating lease liabilities	1,020		1,038
Other	Other	138		158		Other	148		147
Total deferred credits and other liabilities	Total deferred credits and other liabilities	15,276		15,414		Total deferred credits and other liabilities	15,648		15,622

Commitments and contingencies	Commitments and contingencies	0		0		Commitments and contingencies
Capitalization	Capitalization					Capitalization
Long-term debt	Long-term debt	23,205		21,779		Long-term debt	22,818		22,813
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 546,807,793 and 544,025,269 shares outstanding at June 30, 2022 and Dec. 31, 2021, respectively		1,367		1,360
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 550,222,192 and 549,578,018 shares outstanding at March 31, 2023 and December 31, 2022, respectively						Common stock — 1,000,000,000 shares authorized of $2.50 par value; 550,222,192 and 549,578,018 shares outstanding at March 31, 2023 and December 31, 2022, respectively	1,376		1,374
Additional paid in capital	Additional paid in capital	7,960		7,803		Additional paid in capital	8,169		8,155
Retained earnings	Retained earnings	6,747		6,572		Retained earnings	7,370		7,239
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(103)		(123)		Accumulated other comprehensive loss	(97)		(93)
Total common stockholders’ equity	Total common stockholders’ equity	15,971		15,612		Total common stockholders’ equity	16,818		16,675
Total liabilities and equity	Total liabilities and equity	$	59,317	$	57,851	Total liabilities and equity	$	60,945	$	61,188

See Notes to Consolidated Financial Statements	See Notes to Consolidated Financial Statements					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 as of ~~June 30, 2022~~March 31, 2023 and Dec. 31, ~~2021;~~2022; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, and changes in stockholders’ equity for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021;~~2022; and Xcel Energy’s cash flows for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021.~~2022.

All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~June 30, 2022,~~March 31, 2023, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, ~~2021~~2022 balance sheet information has been derived from the audited ~~2021~~2022 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2021.~~2022.

Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2021,~~2022, filed with the SEC on Feb. 23, ~~2022.~~2023.

Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.


1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, ~~2021~~2022 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2. Accounting Pronouncements

As of ~~June 30, 2022,~~March 31, 2023, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on Xcel Energy’s consolidated financial statements.


3. Selected Balance Sheet Data


(Millions of Dollars)	(Millions of Dollars)	June 30, 2022		Dec. 31, 2021		(Millions of Dollars)	March 31, 2023		Dec. 31, 2022
Accounts receivable, net	Accounts receivable, net					Accounts receivable, net
Accounts receivable	Accounts receivable	$	1,195	$	1,124	Accounts receivable	$	1,426	$	1,495
Less allowance for bad debts	Less allowance for bad debts	(111)		(106)		Less allowance for bad debts	(126)		(122)
Accounts receivable, net	Accounts receivable, net	$	1,084	$	1,018	Accounts receivable, net	$	1,300	$	1,373


(Millions of Dollars)	(Millions of Dollars)	June 30, 2022		Dec. 31, 2021		(Millions of Dollars)	March 31, 2023		Dec. 31, 2022
Inventories	Inventories					Inventories
Materials and supplies	Materials and supplies	$	309	$	289	Materials and supplies	$	340	$	330
Fuel	Fuel	216		182		Fuel	169		201
Natural gas	Natural gas	120		160		Natural gas	71		272
Total inventories	Total inventories	$	645	$	631	Total inventories	$	580	$	803

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit ~~facilities capacity.~~facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of ~~June 30, 2022~~March 31, 2023 and Dec. 31, ~~2021.~~2022.

Bilateral Credit Agreement

In April ~~2022,~~2023, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of ~~June 30, 2022,~~March 31, 2023, NSP-Minnesota had ~~$43~~$53 million of outstanding letters of credit under the $75 million bilateral credit agreement.

Long-Term Borrowings and Other Financing Instruments

~~During the six months ended June 30, 2022, Xcel Energy Inc. and its utility subsidiaries~~On April 3, 2023, PSCo issued ~~the following:~~

•~~Xcel Energy issued $700~~$850 million of ~~4.60% unsecured senior notes due June 1, 2032.~~

•~~NSP-Minnesota issued $500 million of 4.50%~~5.25% first mortgage bonds due ~~June~~April 1, ~~2052.~~

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

•~~SPS issued $200 million of 5.15% first mortgage bonds due June 1, 2052.~~2053.

On ~~July 15, 2022, subsequent to the end of the quarter,~~April 21, 2023, NSP-Wisconsin priced a private placement of ~~$100~~$125 million of ~~4.86%~~5.30% first mortgage bonds due ~~September~~June 15, ~~2052.~~2053. The closing of the sale of the bonds is subject to execution of a bond purchase agreement and customary closing conditions and is expected to occur ~~on Sept. 12, 2022.~~in June 2023.

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2021, 5.33 million shares ~~had been~~were issued (approximately $350 million). In ~~the second quarter of~~ 2022, ~~2.13~~4.30 million shares of common stock were issued (approximately ~~$150~~$300 million). As of ~~June 30, 2022,~~March 31, 2023, approximately ~~$300~~$150 million remained available for sale under the ATM program.

Other Equity — Xcel Energy Inc. issued ~~$20~~$15 million and ~~$28~~$10 million of equity through the DRIP during the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.


5. Revenues

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

Three Months Ended June 30, 2022
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 797 $ 257 $ 6 $ 1,060
C&I 1,416 164 7 1,587
Other 37 — 9 46
Total retail 2,250 421 22 2,693
Wholesale 318 — — 318
Transmission 156 — — 156
Other 12 37 — 49
Total revenue from contracts with customers 2,736 458 22 3,216
Alternative revenue and other 187 18 3 208
Total revenues $ 2,923 $ 476 $ 25 $ 3,424

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


		Six Months Ended June 30, 2022									Three Months Ended March 31, 2023
(Millions of Dollars)	(Millions of Dollars)	Electric		Natural Gas		All Other		Total		(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types	Major revenue types									Major revenue types
Revenue from contracts with customers:	Revenue from contracts with customers:									Revenue from contracts with customers:
Residential	Residential	$	1,614	$	919	$	15	$	2,548	Residential	$	875	$	789	$	13	$	1,677
C&I	C&I	2,651		520		9		3,180		C&I	1,352		423		12		1,787
Other	Other	69		—		23		92		Other	36		—		1		37
Total retail	Total retail	4,334		1,439		47		5,820		Total retail	2,263		1,212		26		3,501
Wholesale	Wholesale	577		—		—		577		Wholesale	224		—		—		224
Transmission	Transmission	308		—		—		308		Transmission	163		—		—		163
Other	Other	35		82		—		117		Other	9		48		—		57
Total revenue from contracts with customers	Total revenue from contracts with customers	5,254		1,521		47		6,822		Total revenue from contracts with customers	2,659		1,260		26		3,945
Alternative revenue and other	Alternative revenue and other	302		45		6		353		Alternative revenue and other	104		28		3		135
Total revenues	Total revenues	$	5,556	$	1,566	$	53	$	7,175	Total revenues	$	2,763	$	1,288	$	29	$	4,080


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

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


6. Income Taxes

Reconciliation between the statutory rate and ETR:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended March 31
		2022		2021		2022		2021				2023		2022
Federal statutory rate	Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	Federal statutory rate		21.0	%	21.0	%
State tax (net of federal tax effect)	State tax (net of federal tax effect)	5.2		4.9		5.0		4.9		State tax (net of federal tax effect)		4.8		4.9
Decreases:	Decreases:									Decreases:
Wind PTCs (a)	Wind PTCs (a)	(48.3)		(33.1)		(40.4)		(28.4)		Wind PTCs (a)		(33.1)		(34.4)
Plant regulatory differences (b)	Plant regulatory differences (b)	(5.5)		(6.6)		(5.1)		(6.3)		Plant regulatory differences (b)		(5.5)		(4.8)
Other tax credits, net operating loss & tax credits allowances	Other tax credits, net operating loss & tax credits allowances	(1.4)		(1.0)		(1.5)		(1.1)		Other tax credits, net operating loss & tax credits allowances		(1.6)		(1.5)
Other (net)	Other (net)	(0.1)		0.9		(0.2)		0.1		Other (net)		(0.1)		(0.4)
Effective income tax rate	Effective income tax rate	(29.1)	%	(13.9)	%	(21.2)	%	(9.8)	%	Effective income tax rate		(14.5)	%	(15.2)	%

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

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

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

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


		Three Months Ended June 30		Six Months Ended June 30			Three Months Ended March 31
(Shares in Millions)	(Shares in Millions)	2022	2021	2022	2021	(Shares in Millions)		2023	2022
Basic	Basic	546	539	545	539	Basic		551	545
Diluted (a)	Diluted (a)	546	539	546	539	Diluted (a)		551	545

(a)Diluted common shares outstanding included common stock equivalents of ~~0.3~~ 0.2 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, respectively. Diluted common shares outstanding included common stock equivalents~~ of ~~0.2 million and 0.3 million for the six months ended June 30, 2022 and 2021,~~ 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.~~value.

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

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

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

Specific valuation methods include:

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

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

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

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

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

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

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

FTRs are recognized at ~~estimated~~ fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3.3 classification.

~~If costs of electric transmission congestion increase or decrease for a given path, the value of that particular instrument will likewise increase or decrease.~~ Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

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

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

Unrealized gains for the nuclear decommissioning fund were ~~$1.0 billion and $1.3~~$1 billion as of ~~June 30, 2022~~March 31, 2023 and Dec. 31, ~~2021, respectively,~~2022, and unrealized losses were ~~$76~~$61 million and $7$90 million as of ~~June 30, 2022~~March 31, 2023 and Dec. 31, ~~2021,~~2022, respectively.

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

June 30, 2022
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 53 $ 53 $ — $ — $ — $ 53
Commingled funds 835 — — — 1,209 1,209
Debt securities 668 — 615 6 — 621
Equity securities 407 971 1 — — 972
Total $ 1,963 $ 1,024 $ 616 $ 6 $ 1,209 $ 2,855

~~(a)~~ Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $220 million of equity method investments and $154 million of rabbi trust assets and miscellaneous investments.


		Dec. 31, 2021													March 31, 2023
				Fair Value													Fair Value
(Millions of Dollars)	(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total		(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)	Nuclear decommissioning fund (a)													Nuclear decommissioning fund (a)
Cash equivalents	Cash equivalents	$	64	$	64	$	—	$	—	$	—	$	64	Cash equivalents	$	44	$	44	$	—	$	—	$	—	$	44
Commingled funds	Commingled funds	856		—		—		—		1,294		1,294		Commingled funds	743		—		—		—		1,076		1,076
Debt securities	Debt securities	631		—		666		9		—		675		Debt securities	751		—		707		7		—		714
Equity securities	Equity securities	411		1,222		1		—		—		1,223		Equity securities	507		1,172		2		—		—		1,174
Total	Total	$	1,962	$	1,286	$	667	$	9	$	1,294	$	3,256	Total	$	2,045	$	1,216	$	709	$	7	$	1,076	$	3,008

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes ~~$208~~$228 million of equity method investments and ~~$164~~$137 million of rabbi trust assets and other miscellaneous investments.


	Dec. 31, 2022
			Fair Value
(Millions of Dollars)	Cost		Level 1		Level 2		Level 3		NAV		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	29	$	29	$	—	$	—	$	—	$	29
Commingled funds	803		—		—		—		1,178		1,178
Debt securities	738		—		669		6		—		675
Equity securities	406		999		1		—		—		1,000
Total	$	1,976	$	1,028	$	670	$	6	$	1,178	$	2,882

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and other miscellaneous investments.

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of ~~June 30, 2022:~~March 31, 2023:


		Final Contractual Maturity											Final Contractual Maturity
(Millions of Dollars)	(Millions of Dollars)	Due in 1 year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 years		Total		(Millions of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Debt securities	Debt securities	$	3	$	190	$	232	$	196	$	621	Debt securities	$	1	$	220	$	254	$	239	$	714

Rabbi Trusts

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

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

June 30, 2022
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 20 $ 20 $ — $ — $ 20
Mutual funds 75 78 — — 78
Total $ 95 $ 98 $ — $ — $ 98

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

~~(a)~~ ~~Reported~~trusts were $82 million and $80 million at March 31, 2023 and Dec. 31, 2022, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance ~~sheets.~~sheet.

Derivative ~~Instruments~~Activities and Fair Value Measurements

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

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

As of ~~June 30, 2022,~~March 31, 2023, accumulated other comprehensive loss related to interest rate derivatives included $4$2 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, 2022,~~March 31, 2023, Xcel Energy had no unsettled interest swaps outstanding with a notional amount of $495 million.

See Note 11 for the financial impact of qualifying interest rate ~~derivatives.~~cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.

Wholesale and Commodity Trading ~~Risk~~ — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.

Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of ~~any~~these margins is determined through state regulatory proceedings as well as the operation of the ~~FERC approved~~FERC-approved joint operating agreement.

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

The most significant derivative positions outstanding at March 31, 2023 and Dec. 31, 2022 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.

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

As of ~~June 30, 2022,~~March 31, 2023, Xcel Energy had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b)

June 30, 2022

Dec. 31, 2021

(Amounts in Millions) (a)(b)

March 31, 2023

Dec. 31, 2022

Megawatt hours of electricity

106

Megawatt hours of electricity

Million British thermal units of natural gas

159

156

Million British thermal units of natural gas

117

131

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented inon the consolidated balance sheets.

Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.

As of ~~June 30, 2022, 5~~March 31, 2023, four of Xcel Energy’s 10ten most significant counterparties for these activities, comprising ~~$71~~$60 million, or ~~27%~~32%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. ~~NaN~~

Three of the 10ten most significant counterparties, comprising ~~$58~~$54 million, or ~~22%~~28%, of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. ~~NaN~~

Three of these significant counterparties, comprising ~~$74~~$77 million, or ~~28%~~40%, of this credit exposure, had credit quality less than investment grade, based on internal analysis. ~~NaN~~Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.

As of March 31, 2023 and Dec. 31, 2022, there were $8 million and $4 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.

Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

As of March 31, 2023 and Dec. 31, 2022, there were approximately $84 million and $76 million of derivative liabilities with such underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.

Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2023 and Dec. 31, 2022.


		Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income					Pre-Tax (Gains) Losses Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)	(Millions of Dollars)	Accumulated Other Comprehensive Loss			Regulatory Assets and (Liabilities)					(Millions of Dollars)		Accumulated Other Comprehensive Loss			Regulatory Assets and Liabilities
Three Months Ended June 30, 2022
Derivatives designated as cash flow hedges:
Interest rate		$	1	(a)	$	—		$	—
Total		$	1		$	—		$	—
Other derivative instruments:
Commodity trading		$	—		$	—		$	7	(b)
Electric commodity		—			(26)		(c)	—

Total		$	—		$	(26)		$	7

Six Months Ended June 30, 2022

Three Months Ended March 31, 2023											Three Months Ended March 31, 2023
Derivatives designated as cash flow hedges:	Derivatives designated as cash flow hedges:										Derivatives designated as cash flow hedges:
Interest rate	Interest rate	$	3	(a)	$	—		$	—		Interest rate		$	1	(a)	$	—		$	—
Total	Total	$	3		$	—		$	—		Total		$	1		$	—		$	—
Other derivative instruments:	Other derivative instruments:										Other derivative instruments:
Commodity trading	Commodity trading	$	—		$	—		$	9	(b)	Commodity trading		$	—		$	—		$	(1)	(b)
Electric commodity	Electric commodity	—			(36)		(c)	—			Electric commodity		—			82		(c)	—
Natural gas commodity	Natural gas commodity	—			4		(d)	(17)		(d)(e)	Natural gas commodity		—			9		(d)	(19)		(d)(e)
Total	Total	$	—		$	(32)		$	(8)		Total		$	—		$	91		$	(20)

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

Three Months Ended March 31, 2022											Three Months Ended March 31, 2022
Derivatives designated as cash flow hedges:	Derivatives designated as cash flow hedges:										Derivatives designated as cash flow hedges:
Interest rate	Interest rate	$	6	(a)	$	—		$	—		Interest rate		$	2	(a)	$	—		$	—
Total	Total	$	6		$	—		$	—		Total		$	2		$	—		$	—
Other derivative instruments:	Other derivative instruments:										Other derivative instruments:
Commodity trading	Commodity trading	$	—		$	—		$	48	(b)	Commodity trading		$	—		$	—		$	2	(b)
Electric commodity	Electric commodity	—			(23)		(c)	—			Electric commodity		—			(13)		(c)	—
Natural gas commodity	Natural gas commodity	—			8		(d)	(10)		(d)(e)	Natural gas commodity		—			3		(d)	(17)		(d)(e)
Total	Total	$	—		$	(15)		$	38		Total		$	—		$	(10)		$	(15)

Changes in Level 3 commodity derivatives:

Three Months Ended June 30
(Millions of Dollars) 2022 2021
Balance at April 1 $ 39 $ (13)
Purchases / Issuances (a)
390 63
Settlements (a)
(155) (32)
Net transactions recorded during the period:
Gains recognized in earnings (b)
78 9
Net gains recognized as regulatory assets and liabilities (a)
133 44
Balance at June 30 $ 485 $ 71
Six Months Ended June 30
(Millions of Dollars) 2022 2021
Balance at Jan. 1 $ 19 $ (49)
Purchases / Issuances (a)
394 63
Settlements (a)
(181) (48)
Net transactions recorded during the period:
Gains recognized in earnings (b)
120 47
Net gains recognized as regulatory assets and liabilities (a)
133 58
Balance at June 30 $ 485 $ 71












	Three Months Ended March 31
(Millions of Dollars)	2023		2022
Balance at Jan. 1	$	235	$	19
Purchases (a)	6		5
Settlements (a)	(29)		(50)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)	(13)		42
Net (losses) gains recognized as regulatory assets and liabilities (a)	(121)		24
Balance at March 31	$	78	$	40

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

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

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

Fair Value of Long-Term Debt

~~Other~~As of March 31, 2023, other financial instruments for which the carrying amount did not equal fair value:


		June 30, 2022				Dec. 31, 2021					March 31, 2023				Dec. 31, 2022
(Millions of Dollars)	(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	Long-term debt, including current portion	$	23,856	$	22,076	$	22,380	$	25,232	Long-term debt, including current portion	$	23,719	$	21,167	$	23,964	$	20,897

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of ~~June 30, 2022~~March 31, 2023 and Dec. 31, ~~2021~~2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.


9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost ~~(Credit)~~

Three Months Ended June 30
2022 2021 2022 2021
(Millions of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 25 $ 26 $ 1 $ 1
Interest cost (a)
28 26 4 3
Expected return on plan assets (a)
(52) (51) (5) (5)
Amortization of prior service credit (a)
(1) (1) (1) (2)
Amortization of net loss (a)
18 27 — 2
Net periodic benefit cost (credit) 18 27 (1) (1)
Effects of regulation 1 — — —
Net benefit cost (credit) recognized for financial reporting $ 19 $ 27 $ (1) $ (1)


		Six Months Ended June 30									Three Months Ended March 31
		2022		2021		2022		2021			2023		2022		2023		2022
(Millions of Dollars)	(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits				(Millions of Dollars)	Pension Benefits				Postretirement Health Care Benefits
Service cost	Service cost	$	49	$	52	$	1	$	1	Service cost	$	18	$	24	$	—	$	—
Interest cost (a)	Interest cost (a)	55		52		8		7		Interest cost (a)	40		27		5		4
Expected return on plan assets (a)	Expected return on plan assets (a)	(104)		(103)		(9)		(9)		Expected return on plan assets (a)	(52)		(52)		(4)		(4)
Amortization of prior service credit (a)	Amortization of prior service credit (a)	(1)		(1)		(3)		(4)		Amortization of prior service credit (a)	—		—		—		(2)
Amortization of net loss (a)	Amortization of net loss (a)	37		54		1		3		Amortization of net loss (a)	5		19		1		1
Settlement charge (b)	Settlement charge (b)	(1)		—		—		—		Settlement charge (b)	—		(1)		—		—
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	35		54		(2)		(2)		Net periodic benefit cost (credit)	11		17		2		(1)
Effects of regulation	Effects of regulation	6		(1)		1		1		Effects of regulation	5		5		—		1
Net benefit cost (credit) recognized for financial reporting		$	41	$	53	$	(1)	$	(1)
Net benefit cost recognized for financial reporting										Net benefit cost recognized for financial reporting	$	16	$	22	$	2	$	—

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

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

~~NaN~~One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling onin June ~~30,~~ 2022 granting plaintiffs’ class certification. ~~Defendants will work together to prepare and file a petition appealing the class~~ ~~certification ruling to~~In April 2023, the Seventh ~~Circuit.~~Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected later this year. Xcel Energy ~~has concluded that a~~considers the reasonably possible loss ~~is remote for the remaining lawsuit.~~associated with this litigation to be immaterial.

Comanche Unit 3 Litigation — In ~~September~~ 2021, CORE filed a lawsuit in Denver County District ~~Court. CORE alleges~~Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In January 2022, the Court granted PSCo’s motion ~~and dismissed~~to dismiss CORE’s claims for unjust enrichment, declaratory judgment and damages for replacement power costs. In ~~February 2022, CORE disclosed that it is claiming in excess of $125 million in total damages.~~

In April 2022, CORE filed a supplement to include the January 2022 ~~outage. It~~outage and damages related to this event. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, CORE disclosed its expert witness, who estimated damages incurred of $270 million. Also in February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. PSCo continues to believe CORE's claims ~~additional undisclosed damages arising from this event.~~are without merit and disputes CORE’s right to withdraw.

Rate Matters and Other

Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

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

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

In March 2022, following February 2022 ALJ hearings, the OAG recommended a disallowance of up to $148 million, the largest recommendation among the intervenor positions. In May 2022, the ALJs found that the natural gas costs for Winter Storm Uri were prudently incurred and recommended no disallowances. A MPUC decision is expected in August 2022.

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

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

In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.

In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota. A final decision by the MPUC is expected in ~~mid-2023.~~mid-2024. A loss related to this matter is deemed remote.

~~Westmoreland Arbitration~~ —In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPA and Western Fuels Association, seeking recovery of alleged business losses due to a turbine failure at Sherco Unit 3, which currently include $19 million in damages, plus prejudgment interest. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards.

~~NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. In the second quarter of 2022, this matter settled for $2 million.~~

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

The FERC ~~has~~ subsequently issued various related orders (including Opinion Nos. 569, 569A and 569B) related to ROE methodology/calculations and timing. NSP-Minnesota has ~~recognized a liability for its best estimate of final~~processed refunds to customers for applicable complaint ~~periods.~~periods based on the ROE in the most recent applicable opinions.

The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. ~~A decision~~In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders, and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected ~~by the end of the third quarter of 2022.~~

to be immaterial.

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

In ~~July~~ 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In ~~February~~ 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In ~~March~~ 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In ~~August~~ 2021, the D.C. Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates.

In ~~October~~ 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In ~~March~~ 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in ~~April~~ 2018. The FERC subsequently issued a tolling order granting a rehearing for further ~~consideration in May 2018.~~consideration. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In ~~October~~ 2020, SPS filed a petition for review of the FERC’s ~~March~~ 2018 ~~order and May 2018 tolling order~~orders at the D.C. Circuit. In February 2022, FERC issued an order rejecting SPS’ request for hearing. SPS has appealed that order. That appeal has been combined with SPS’ prior appeal.

~~Contract Termination~~ —SPS and LP&L have a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million, to the benefit of SPS’ remaining customers. LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The agreement is subject to approval by the PUCT and FERC.

Environmental

MGP, Landfill and Disposal Sites

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

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

Environmental Requirements — Water and Waste

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

As of March 31, 2023, Xcel Energy ~~has 8~~had eight regulated ash units in operation.

~~In August 2020, the EPA published its final rule to implement closure by April 2021 for CCR impoundments. This final rule required Xcel Energy to expedite closure plans for two impoundments.~~

PSCo built an alternative collection and treatment system to remove a bottom ash pond from service. The total cost of the treatment system is approximately $25 million. PSCo removed the pond from service in June 2021 and did not meet the April 2021 deadline. PSCo has ~~negotiated a compliance order with the EPA addressing the closure deadline, which includes a penalty of less than $1 million paid by PSCo.~~

~~The EPA recently clarified its interpretation/guidance regarding CCR units with ash in place and contact with groundwater. This guidance affects 2 of PSCo’s facilities. PSCo is exploring~~executed an agreement with a ~~company~~third party that ~~would~~will excavate and process ~~the~~ ash for beneficial use (at two sites) at a cost ~~to PSCo~~ of approximately ~~$30 - $40~~$45 million. An estimated liability has been recorded ~~within that range. Xcel Energy anticipates these costs will~~and amounts are expected to be fully recoverable through regulatory mechanisms.

Investigation and feasibility studies for additional corrective action related to offsite groundwater are ongoing (at three Colorado sites). While the results are uncertain, additional costs are estimated to be at ~~2 locations. The total cost is uncertain, but could~~least $30 million. A liability has been recorded for the portion of these actions that are estimable/probable, and are expected to be ~~up to $35 million. PSCo is continuing to assess the financial and~~fully recoverable through regulatory ~~impacts.~~mechanisms.

Federal Clean Water Act Section 316(b) — The ~~federal~~Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure ~~that these structures~~they reflect the best technology available for minimizing impingement and entrainment of aquatic species. ~~Xcel Energy estimates~~

Estimated capital expenditures of approximately ~~$40~~$45 million may be required to comply with ~~impingement and entrainment~~the requirements. ~~Xcel Energy believes 6 NSP-Minnesota plants and 2 NSP-Wisconsin plants could be required to make improvements to reduce impingement and entrainment.~~ Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.

Monticello Tritium — Monticello regularly monitors onsite tritium levels (a weak radioactive isotope that is a byproduct of plant operations) from releases in groundwater monitoring wells onsite. In late 2022, Xcel Energy detected a release of tritium to groundwater and reported the event to the NRC and the State of Minnesota. Xcel Energy has completed repairs, replaced the source of the release and is extracting the impacted groundwater. Xcel Energy anticipates costs to extract and contain the impacted groundwater from this release to be immaterial. The water is fully contained on-site and has not been detected in any drinking water. The release does not represent a risk to human health or the environment.

Environmental Requirements — Air

~~Reasonable Progress Rule:~~Regional Haze Rules — In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes ~~sulfur dioxide~~SO2 emission limitations ~~that~~which would require the installation of dry scrubbers on Tolk Units 1 and 2; compliance would have been required by February 2021. SPS appealed the EPA’s decision and obtained a stay of the final rule.

In ~~March~~ 2017, the ~~Fifth Circuit remanded~~EPA adopted a final BART rule for Texas. Under that rule, Harrington Units 1, 2, and 3 and Tolk Units 1 and 2 participate in intrastate SO2 budget and trading program. The rule also implemented participation in a federal ozone season NOx budget and trading program, named the Cross State Air Pollution Rule. The EPA is reconsidering this rule ~~to the EPA~~and a proposal for reconsideration ~~leaving the stay in effect. In a future rulemaking, the EPA will address whether sulfur dioxide emission reductions beyond those required~~is anticipated in the ~~BART alternative rule referenced above are needed at Tolk under the “reasonable progress” requirements. As states are now proceeding with the~~ second ~~regional haze planning period, the EPA may choose not to act on the remanded rule, but could impose additional requirements as part~~quarter of ~~a BART reconsideration or as part of the second planning period.~~2023.

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.

~~Table of Contents~~

Components of lease expense:

Three Months Ended June 30
(Millions of Dollars) 2022 2021
Operating leases
PPA capacity payments $ 60 $ 56
Other operating leases (a)
9 9
Total operating lease expense (b)
$ 69 $ 65
Finance leases
Amortization of ROU assets $ 1 $ 2
Interest expense on lease liability 4 4
Total finance lease expense $ 5 $ 6


	Three Months Ended March 31
(Millions of Dollars)	2023		2022
Operating leases
PPA capacity payments	$	60	$	63
Other operating leases (a)	12		13
Total operating lease expense (b)	$	72	$	76
Finance leases
Amortization of ROU assets	$	1	$	1
Interest expense on lease liability	4		4
Total finance lease expense	$	5	$	5

(a)Includes short-term lease expense of $2of $2 million and $1 million for 2023 and 2022, ~~and 2021.~~

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

Six Months Ended June 30
(Millions of Dollars) 2022 2021
Operating leases
PPA capacity payments $ 123 $ 114
Other operating leases (a)
20 17
Total operating lease expense (b)
$ 143 $ 131
Finance leases
Amortization of ROU assets $ 2 $ 4
Interest expense on lease liability 8 8
Total finance lease expense $ 10 $ 12

~~(a)Includes short-term lease expense o~~f ~~$3 million for 2022 and 2021.~~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.

Commitments under operating and finance leases as of ~~June 30, 2022:~~March 31, 2023:


(Millions of Dollars)	(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)		(Millions of Dollars)	PPA Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases (a)
Total minimum obligation	Total minimum obligation	$	1,303	$	171	$	1,474	$	236	Total minimum obligation	$	1,223	$	257	$	1,480	$	225
Interest component of obligation	Interest component of obligation	(186)		(31)		(217)		(165)		Interest component of obligation	(160)		(76)		(236)		(160)
Present value of minimum obligation	Present value of minimum obligation	$	1,117	140		1,257		71		Present value of minimum obligation	$	1,063	181		1,244		65
Less current portion	Less current portion					(210)		(4)		Less current portion					(224)		(2)
Noncurrent operating and finance lease liabilities	Noncurrent operating and finance lease liabilities					$	1,047	$	67	Noncurrent operating and finance lease liabilities					$	1,020	$	63

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

Variable Interest Entities

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

~~The utility subsidiaries had approxi~~ma~~tely 4,037 MW~~ ~~and 4,062 MW of capacity~~In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under ~~long-term~~contract. These specific PPAs ~~at June 30, 2022 and Dec. 31, 2021, respectively, with entities that have been determined to be~~create a variable interest ~~entities.~~ in the IPP.

Xcel Energy concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had approximately 4,053 MW and 3,961 MW of capacity under long-term PPAs at March 31, 2023 and Dec. 31, 2022, respectively, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2041.

Other

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

12. Segment Information

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

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

Xcel Energy has the following reportable segments:

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

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

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

Xcel Energy had equity method investments of ~~$220~~$228 million and ~~$208~~$219 million as of ~~June 30, 2022~~March 31, 2023 and Dec. 31, ~~2021,~~2022, respectively, included in the natural gas utility and all other segments.

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

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

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

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

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

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

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,~~March 31, 2023 and 2022, ~~and 2021,~~ there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.


Results of Operations

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

Summarized diluted EPS for Xcel Energy:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended March 31
Diluted Earnings (Loss) Per Share	Diluted Earnings (Loss) Per Share	2022		2021		2022		2021		Diluted Earnings (Loss) Per Share		2023		2022
PSCo	PSCo	$	0.24	$	0.25	$	0.56	$	0.56	PSCo		$	0.39	$	0.32
NSP-Minnesota	NSP-Minnesota	0.22		0.21		0.45		0.45		NSP-Minnesota		0.25		0.23
SPS	SPS	0.17		0.13		0.27		0.23		SPS		0.10		0.10
NSP-Wisconsin	NSP-Wisconsin	0.03		0.03		0.11		0.09		NSP-Wisconsin		0.08		0.09
Earnings from equity method investments — WYCO	Earnings from equity method investments — WYCO	0.01		0.01		0.02		0.02		Earnings from equity method investments — WYCO		0.01		0.01
Regulated utility (a)	Regulated utility (a)	0.67		0.62		1.41		1.35		Regulated utility (a)		0.83		0.75
Xcel Energy Inc. and Other	Xcel Energy Inc. and Other	(0.07)		(0.04)		(0.11)		(0.10)		Xcel Energy Inc. and Other		(0.07)		(0.05)
Total (a)	Total (a)	$	0.60	$	0.58	$	1.30	$	1.25	Total (a)		$	0.76	$	0.70

(a) Amounts may not add due to rounding.

Summary of Earnings

Xcel Energy — Xcel Energy’s ~~GAAP second~~first quarter diluted earnings were ~~$0.60~~$0.76 per share in ~~2022~~2023 compared with ~~$0.58~~$0.70 per share in ~~2021.~~2022. The increase was driven by ~~regulatory~~ recovery of ~~capital~~electric and natural gas infrastructure investment, partially offset by higher depreciation, ~~interest expense and~~ O&M ~~expenses. Costs for natural gas sold~~expenses and ~~transported significantly increased in 2022 primarily due to market price fluctuations. However, fluctuations~~interest charges. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

PSCo — Earnings increased $0.07 per share for the first quarter of 2023. The higher earnings primarily reflect the timing of recovery of electric and natural gas infrastructure investment and the impact of colder than normal weather, partially offset by increased depreciation, O&M expenses and interest charges. Incremental investment recovery was implemented for electric operations in April 2022 and natural gas operations in November 2022, resulting in higher revenues in the first quarter of 2023 compared to 2022. The year-over-year impact of these higher revenues is not expected to continue throughout the rest of the year. Earnings are not a result of higher natural gas prices as PSCo does not profit on fuel or power costs purchased for its customers.

NSP-Minnesota — Earnings increased $0.02 per share for the first quarter of 2023. The increase is primarily due to recovery of electric infrastructure investment, partially offset by increased O&M expenses and depreciation.

SPS — Earnings were flat for the first quarter of 2023. Recovery of electric infrastructure investment and strong sales growth were offset by higher depreciation and O&M expenses.

NSP-Wisconsin — Earnings decreased $0.01 per share for the ~~second~~first quarter of ~~2022~~2023. Recovery of electric and natural gas infrastructure investment were flat year-to-date. Year-to-date earnings reflect a Winter Storm Uri cost disallowance (see Other section) and unrecovered incremental purchased power costs due to the Comanche Unit 3 outage (see Other section).

~~NSP-Minnesota~~ — ~~Earnings increased $0.01 per share for the second quarter of 2022 and were flat year-to-date, as regulatory recovery of capital investment was~~more than offset by ~~increased depreciation and interest expense.~~

~~SPS~~ ~~— Earnings increased $0.04 per share for the second quarter~~impacts of ~~2022 and year-to-date, primarily due to regulatory outcomes, strong sales growth and favorable weather.~~

~~NSP-Wisconsin~~ ~~— Earnings were flat for the second quarter of 2022 and increased $0.02 per share year-to-date. The year-to-date increase reflects the impact of regulatory rate outcomes, sales growth and favorable~~warmer winter weather, ~~partially offset by~~ higher depreciation and O&M expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company and earnings from Energy Impact Partners funds equity method investments. Earnings decreased $0.02 per share for the first quarter, largely attributable to higher interest charges.

Changes in GAAP and Ongoing Diluted EPS

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

Diluted Earnings (Loss) Per Share Three Months Ended June 30 Six Months Ended June 30
GAAP and ongoing diluted EPS — 2021 $ 0.58 $ 1.25
Components of change - 2022 vs. 2021
Higher electric revenues, net of electric fuel and purchased power 0.26 0.34
Lower effective tax rate (ETR) (a)
0.06 0.10
(Lower) higher natural gas revenues, net of cost of natural gas sold and transported (0.01) 0.04
Higher depreciation and amortization (0.15) (0.21)
Higher interest charges (0.05) (0.06)
Higher taxes (other than income taxes) (0.03) (0.04)
Higher O&M expenses (0.02) (0.04)
Lower other (expense) income (0.01) (0.02)
Other, net (0.03) (0.06)
GAAP and ongoing diluted EPS — 2022 $ 0.60 $ 1.30


Diluted Earnings (Loss) Per Share	Three Months Ended March 31
GAAP and ongoing diluted EPS — 2022	$	0.70

Components of change - 2023 vs. 2022
Higher electric revenues, net of electric fuel and purchased power	0.15
Higher natural gas revenues, net of cost of natural gas sold and transported	0.09
Lower effective tax rate (ETR) (a)	0.02
Higher depreciation and amortization	(0.08)
Higher O&M expenses	(0.06)
Higher interest charges	(0.05)
Higher taxes (other than income taxes)	(0.02)

Other, net	0.01
GAAP and ongoing diluted EPS — 2023	$	0.76

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

Statement of Income Analysis

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

Estimated Impact of Temperature Changes on Regulated Earnings —Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.

As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, decoupling mechanisms in Colorado and proposed ~~sales true-up~~decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric ~~utility.~~utility in those jurisdictions.

Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.

Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.

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

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

Three Months Ended June 30 Six Months Ended June 30
2022 vs. Normal 2021 vs. Normal 2022 vs. 2021 2022 vs. Normal 2021 vs. Normal 2022 vs. 2021
HDD 6.3 % 1.7 % 3.2 % 9.1 % 1.4 % 7.1 %
CDD 29.7 3.5 31.7 28.9 3.0 31.0
THI 21.3 88.9 (33.1) 21.0 88.4 (33.0)


	Three Months Ended March 31
		2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
HDD		1.4	%	9.7	%	(7.3)	%

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


		Three Months Ended June 30						Six Months Ended June 30							Three Months Ended March 31
		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021				2023 vs. Normal		2022 vs. Normal		2023 vs. 2022
Retail electric	Retail electric	$	0.028	$	0.056	$	(0.028)	$	0.049	$	0.055	$	(0.006)	Retail electric		$	0.002	$	0.020	$	(0.018)
Decoupling and sales true-up		(0.013)		(0.044)		0.031		(0.023)		(0.041)		0.018
Decoupling														Decoupling		(0.006)		(0.010)		0.004
Electric total	Electric total	$	0.015	$	0.012	$	0.003	$	0.026	$	0.014	$	0.012	Electric total		$	(0.004)	$	0.010	$	(0.014)
Firm natural gas	Firm natural gas	0.003		0.002		0.001		0.019		0.005		0.014		Firm natural gas		0.029		0.016		0.013
Total	Total	$	0.018	$	0.014	$	0.004	$	0.045	$	0.019	$	0.026	Total		$	0.025	$	0.026	$	(0.001)

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


		Three Months Ended June 30											Three Months Ended March 31
		PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy			PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual	Actual											Actual
Electric residential	Electric residential	(6.3)	%	(5.9)	%	6.5	%	(3.0)	%	(4.2)	%	Electric residential	0.6	%	(4.2)	%	(2.7)	%	(6.4)	%	(2.4)	%
Electric C&I	Electric C&I	(1.1)		0.6		11.7		2.5		3.2		Electric C&I	(1.2)		(1.8)		7.3		—		1.0
Total retail electric sales	Total retail electric sales	(2.8)		(1.4)		10.8		0.9		1.2		Total retail electric sales	(0.6)		(2.6)		5.3		(2.0)		—
Firm natural gas sales	Firm natural gas sales	(9.6)		27.3		N/A		22.5		2.2		Firm natural gas sales	5.8		(10.1)		N/A		(14.3)		(1.1)

Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized
Electric residential (3.2) % 0.7 % (0.8) % 1.0 % (1.0) %
Electric C&I 1.0 4.1 10.4 3.9 4.8
Total retail electric sales (0.4) 3.0 8.2 3.0 3.1
Firm natural gas sales (2.5) 6.9 N/A 8.3 1.2

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

•PSCo — Residential sales declined due to decreased use per customer, partially offset by a ~~1.1%~~1.3% increase in customers. The ~~growth in~~ C&I sales decline was attributable to decreased use per customer, primarily due to a ~~1.1% increase in customers, primarily in the professional services and retail sectors.~~two-month outage at a large manufacturing sector customer.

•NSP-Minnesota — Residential sales ~~growth reflects a 1.2% increase in customers,~~declined due to decreased use per customer, partially offset by ~~decreased use per customer.~~a 1.0% increase in customers. The ~~growth in~~ C&I sales decline was ~~primarily due~~attributable to ~~higher~~lower use per customer, ~~particularly~~primarily driven by declines in the ~~manufacturing, real estate~~educational, transportation and ~~leasing,~~warehousing and ~~food service~~retail trade sectors.

•SPS — Residential sales ~~declined due~~growth was primarily attributable to ~~a lower~~increased use per customer, ~~partially offset by~~in addition to a ~~1.0%~~0.8% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector.

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

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

•Natural gas sales reflect a ~~higher~~lower use per residential customer ~~use, primarily~~ in ~~NSP-Minnesota and NSP-Wisconsin, as well as a 1.2% increase in residential customers and a 0.5%~~all jurisdictions, partially offset by an increase in C&I ~~customers.~~use per customer in PSCo. In addition, residential and C&I customer growth was 1.2% and 0.7%, respectively.

Electric Margin

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

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact due to fuel recovery ~~mechanisms that recover fuel expenses.~~mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.

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


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended March 31
(Millions of Dollars)	(Millions of Dollars)	2022		2021		2022		2021		(Millions of Dollars)		2023		2022
Electric revenues	Electric revenues	$	2,923	$	2,597	$	5,556	$	5,467	Electric revenues		$	2,763	$	2,633
Electric fuel and purchased power	Electric fuel and purchased power	(1,181)		(1,047)		(2,275)		(2,433)		Electric fuel and purchased power		(1,117)		(1,094)
Electric margin	Electric margin	$	1,742	$	1,550	$	3,281	$	3,034	Electric margin		$	1,646	$	1,539

(Millions of Dollars) Three Months Ended June 30, 2022 vs. 2021 Six Months Ended June 30, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin) $ 124 $ 187
Revenue recognition for the Texas rate case surcharge (a)
85 85
Sales and demand (b)
38 60
Non-fuel riders 7 41
Conservation and demand side management (offset in expense) 9 22
Estimated impact of weather (net of decoupling/sales true-up) 2 9
PTCs flowed back to customers (offset by lower ETR) (50) (103)
Proprietary commodity trading, net of sharing (c)
(8) (33)
Comanche Unit 3 outage unrecovered purchased power cost (d)
(8) (18)
Other (net) (7) (3)
Total increase $ 192 $ 247


(Millions of Dollars)	Three Months Ended March 31, 2023 vs. 2022
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico, South Dakota and Wisconsin)	$	88
Sales and demand (a)	18
Wholesale transmission (net)	17
Non-fuel riders	15
Conservation and demand side management (offset in expense)	(17)
PTCs flowed back to customers (offset by a lower ETR)	(12)
Estimated impact of weather, net of decoupling	(10)
Other (net)	8




Total increase	$	107

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

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

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

~~(d)See Other section for more information.~~

Natural Gas Margin

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

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

Natural gas revenues, cost of natural gas sold and transported and ~~margin and explanation of the changes are listed as follows:~~margin:


		Three Months Ended June 30				Six Months Ended June 30					Three Months Ended March 31
(Millions of Dollars)	(Millions of Dollars)	2022		2021		2022		2021		(Millions of Dollars)		2023		2022
Natural gas revenues	Natural gas revenues	$	476	$	449	$	1,566	$	1,096	Natural gas revenues		$	1,288	$	1,090
Cost of natural gas sold and transported	Cost of natural gas sold and transported	(251)		(218)		(961)		(517)		Cost of natural gas sold and transported		(844)		(710)
Natural gas margin	Natural gas margin	$	225	$	231	$	605	$	579	Natural gas margin		$	444	$	380

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased ~~$14~~$48 million for the ~~second quarter and $32 million year-to-date. O&M costs increased~~first quarter. Increase was primarily due to ~~recognition~~timing of ~~previously deferred amounts related to~~recovery mechanisms, generation outages and emergent work; higher bad debt expenses; the ~~Texas Electric Rate Case, additional~~impact of inflationary pressures, including labor increases, and investments in ~~technology and customer~~electric vehicle programs and ~~higher costs for storms and vegetation management. These increases were partially offset by a reduction in employee benefit costs and timing of certain power plant overhaul costs.~~other customer products.

Depreciation and Amortization — Depreciation and amortization increased ~~$110~~$62 million for the ~~second~~first quarter, ~~and $151 million year-to-date. The increase was~~ primarily driven by ~~several wind farms going into service, normal~~ system expansion and ~~recognition~~the implementation of ~~previously deferred costs related to the Texas Electric Rate Case.~~

~~Other (Expense) Income~~ ~~— Other (expense) income decreased $9 million for the second quarter~~new depreciation rates in Colorado and ~~$13 million year-to-date, largely related to rabbi trust performance, which is primarily offset in O&M expenses (employee benefit costs).~~Minnesota.

Interest Charges — Interest charges increased ~~$35~~$39 million for the ~~second~~first quarter, ~~and $44 million year-to-date,~~ largely due to higher interest rates and increased long-term debt levels to fund capital ~~investments and deferred balances related to Winter Storm Uri.~~investments.

~~Income Taxes~~ — Income tax benefit increased $36 million for the second quarter and $64 million year-to-date, primarily driven by an increase in wind PTCs due to greater production at existing wind farms and several new wind farms 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.

In April 2022, the Internal Revenue Service published inflation factors used to determine the PTC rate. As a result, the 2022 PTC rate on the sale of electricity produced from wind is 2.6 cents per kilowatt hour, compared to 2.5 cents for 2021.


Public Utility Regulation and Other

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.

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

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

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2021~~2022 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings

2022 Minnesota Electric Rate Case — InIn October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.2%, a ~~52.50%~~52.5% equity ratio and forward test years.

~~The request is detailed as follows:~~

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

In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. ~~A current liability~~In November 2022, NSP-Minnesota revised its rate request to $498 million over three years.

On March 31, 2023, the ALJ’s report was issued. NSP-Minnesota estimates that ~~represents NSP-Minnesota’s best estimate~~the ALJ recommendation would result in a rate increase of approximately $386 million over three years from 2022-2024, based on a ~~refund obligation~~ROE of 9.87% and an equity ratio of 52.5%. In addition, it also reflects rate reductions associated with ~~interim rates was recorded~~certain wind and nuclear generation life extensions and MISO capacity revenues and related tracker, as ofproposed in NSP-Minnesota’s revised rate request. A MPUC order is expected by June 30, ~~2022.~~2023.

~~Next steps in the procedural schedule are expected~~Proposed ALJ modifications to beNSP-Minnesota’s request were as follows:

•~~Intervenor testimony: Oct. 3, 2022.~~


(Millions of Dollars)	2022		2023		2024
NSP-Minnesota’s revised revenue request	$	234	$	328	$	498

ALJ recommended adjustments:
PTC forecast	(28)		(2)		(1)
Impact of ROE change	(27)		(29)		(30)
O&M expenses	(15)		(17)		(18)
Property tax	—		(11)		(23)
Sherco 3 and A.S. King remaining life	—		—		(35)
Other, net	3		(9)		(5)
Total adjustments	(67)		(68)		(112)
Total proposed revenue change	$	167	$	260	$	386

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

•~~Hearing: Dec. 13-16, 2022.~~

•~~ALJ Report: March 31, 2023.~~

•~~MPUC Order: June 30, 2023.~~

2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million.

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

~~Next steps in~~In March 2023, the ~~procedural schedule are expected to be as follows:~~MPUC approved a settlement between NSP-Minnesota and various parties, which includes the following key terms:

•~~Intervenor testimony: Aug. 30,~~Base rate revenue increase of $21 million, with a true up to weather normalized actual sales for 2022.

•~~Rebuttal testimony: Oct. 4, 2022.~~Revenue decoupling mechanism.

•~~Hearing: Nov. 1-4, 2022.~~Symmetrical property tax true-up.

•~~ALJ Report: Feb. 6, 2023.~~ROE of 9.57%.

•~~MPUC Order: April 26, 2023.~~

~~2021 North Dakota Natural Gas Rate Case —~~ ~~In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.5%. The filing is based on a requested ROE of 10.5%, an equity~~Equity ratio of ~~52.54%, a 2022 forecast test year and a rate base of $124 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.~~52.5%.

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

2022 South Dakota Electric Rate Case — OnIn June ~~30,~~ 2022, NSP-Minnesota filed a South Dakota electric rate case (first since 2014) seeking a revenue increase of approximately $44 million. The filing iswas based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a requested ROE of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. ~~Final~~ ~~rates are~~A commission decision is expected ~~to be effective in the first quarter of 2023.~~later this year.

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

In March 2023, the MPUC ~~is expected in~~approved the ~~third or fourth quarter 2022.~~revised projects.

~~Sherco Solar Proposal~~2022 Upper Midwest RFP — In ~~April 2021,~~August 2022, NSP-Minnesota ~~proposed to add 460~~launched a RFP for 900 MW of solar ~~facilities at the Sherco site with an initial estimated investment of approximately $575 million. NSP-Minnesota requested a delay in the procedural schedule due~~or solar-plus-storage hybrid resources to recent solar supply chain disruptions and potential impact on pricing. An updated request was filed with the MPUC in July 2022 and a decision is now anticipated in the fourth quarter of 2022 or the first quarter of 2023. The proposed facilities are still expected to be in-servicecome online by the end of ~~2025.~~2025, including up to 300 MW of capacity to reuse the Sherco Unit 2 interconnection rights when the coal facility retires at the end of 2023.

NSP-Minnesota completed its bid evaluation process in December 2022 and will file for approval of selected projects in the second quarter of 2023.

~~Wind PPA Buyout~~2022 Minnesota Electric Vehicle Proposal — In ~~July~~August 2022, NSP-Minnesota ~~requested approval from~~filed a request with the MPUC for ~~updated agreements with ALLETE Clean Energy~~approval of approximately $320 million of capital investments (2022 through 2026) to ~~purchase~~support a public charging network, electric school bus pilot, and other expansions and modifications to its residential and commercial electric vehicle programs.

In February 2023, other parties to the ~~repowered 100 MW Northern Wind Facility and 22 MW Rock Aetna Facility. The MPUC previously approved~~contested proceeding filed their direct testimony ranging in levels of support/opposition to the proposals. In March 2023, the ALJ granted NSP-Minnesota’s ~~acquisition of the projects, but the agreements required further approval due to updated terms of the acquisition, including an increase~~request for a 60-day stay in the ~~purchase price. The price increase~~case so that the parties could pursue potential settlement. An evidentiary hearing has not been scheduled but is ~~offset by higher~~ expected ~~PTC benefits, resulting~~ in ~~minimal change to the net cost to customers.~~

~~2022 RES Electric Rider —~~ ~~In November 2021, NSP-Minnesota filed the RES Rider. The requested amount of $264 million includes a true-up (2020 and 2021 riders) of $154 million and the 2022 requested amount of $110 million.~~June 2023. A MPUC decision is ~~pending.~~expected in late 2023.

Table of Contents

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

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

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

Nuclear Power Operations

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2021~~2022 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, ~~2021,~~2022, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference.

NSP-Wisconsin

~~Pending and Recently Concluded~~Upcoming Regulatory Proceedings

~~Michigan Natural Gas~~Wisconsin Rate Case — ~~—In July 2022,~~On April 28, 2023, NSP-Wisconsin ~~filed an application~~expects to file a base rate filing with the ~~Public Service Commission~~PSCW seeking an electric increase of ~~Michigan seeking~~$40 million (an overall rate increase of 4.8%) and a ~~revenue increase in base~~ natural gas ~~rates~~increase of $1$9 million ~~for~~(an overall rate increase of 5.3%). The rate request is based on a 2024 forward-looking test year with a requested ROE of 10.25% and a 52.5% equity ratio. A final decision by the ~~period of 2023-2025.~~PSCW is expected late fourth quarter 2023.

PSCo

Pending and Recently Concluded Regulatory Proceedings

Colorado ~~Natural Gas~~Electric Rate Case — In ~~January~~November 2022, PSCo filed ~~a request with the CPUC~~an electric rate case seeking a net increase ~~to retail natural gas rates~~ of ~~$107 million.~~$262 million, or 8.2%. The total ~~change to base rates is $215~~request reflects a $312 million increase, which ~~reflects the transfer~~includes $50 million of ~~$108 million previously~~authorized costs currently recovered ~~from customers~~ through ~~the PSIA rider.~~various rider mechanisms. The request is based on a 10.25% ROE, an equity ratio of ~~55.66%~~55.7% and a ~~2022 current~~2023 forecast test year with a ~~projected~~2023 year-end rate base of ~~$3.6~~$11.3 billion. PSCo ~~has~~ requested ~~a proposed~~rates effective ~~date of Nov. 1, 2022.~~in September 2023.

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

On June 15, 2022, eight parties filed testimony, with the CPUC Staff and the UCA filing comprehensive testimony. The Staff and UCA both recommended a historic test year with average rate base and no step increases for 2023 and 2024.

~~Proposed modifications to PSCo's request:~~

2022 Rate Request (Millions of Dollars) Staff UCA
Filed base revenue request $ 215 $ 215
Less: previously authorized costs (existing riders) 108 108
Filed net increase to revenue 107 107
Recommended adjustments:
Test year adjustments (33) (41)
ROE (42) (42)
Weather normalization adjustment — (7)
Depreciation expense change 14 —
Other, net (15) (5)
Total recommended adjustments (76) (95)
Total proposed revenue change $ 31 $ 12

~~Positions on PSCo's filed gas rate request:~~

Recommended Position Staff UCA
ROE 9.00 % 9.00 %
Equity 55.00 % 51.50 %
Test year Historic Historic

~~In July 2022, PSCo filed rebuttal testimony and updated its revenue request from $215 million to $202 million.~~

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

•~~Settlement deadline: Aug.~~Answer testimony May 3, ~~2022.~~2023.

•~~Evidentiary hearings: Aug. 17-23, 2022.~~Rebuttal testimony: May 31, 2023.

•Settlement deadline: June 14, 2023.

•Hearing: July 6-21, 2023.

•Statement of position: ~~Sept. 21, 2022.~~Aug. 10, 2023.

A CPUC decision is expected in the third quarter of 2023.

Colorado ~~Electric Rate Request~~Resource Plan — In ~~July 2021, PSCo filed a request with the CPUC.~~ ~~In March~~August 2022, the CPUC approved an ~~unopposed settlement that included a net electric rate increase of $177 million, a ROE of 9.3% and an equity ratio of 55.69%. Rates became effective April 1, 2022.~~

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

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

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

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

~~In July 2022, the CPUC modified the PIMs related to cost controls and project timing.~~

~~Colorado Resource Plan Settlement— In June 2022, the CPUC verbally approved a revised~~updated settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. ~~PSCo expects to file a recovery method docket in the fall.~~

~~Key settlement terms include:~~

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

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

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

•~~Addition of ~2,400 MW of wind.~~

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

•~~Addition of 400 MW of storage.~~

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

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

~~Colorado Partial Settlement —~~ In ~~October~~ ~~2021,~~April 2023, PSCo filed a ~~comprehensive~~coal cost recovery settlement with the CPUC ~~Staff and the Colorado Energy Office, which proposed to address four outstanding~~that includes regulatory ~~items, including~~asset recovery of ~~fuel costs related to Winter Storm Uri, disputed revenue associated with~~ the ~~2020 electric decoupling pilot program year, replacement power costs associated with an extended outage~~remaining plant balances at retirement and a potential bundled securitization of the remaining coal plant book values including Comanche Unit 3 ~~duri~~in 2031.~~ng 2020 and deferred customer bad debt balances associated~~

In December 2022, PSCo commenced the RFP process for generation resources with ~~COVID-19. In July 2022,~~bids due in March 2023. After reviewing the bids received, PSCo will file a report with the CPUC ~~approved~~with recommended resource acquisitions and a CPUC decision on the ~~settlement, with an $8 million disallowance relating~~resources to ~~the Winter Storm Uri fuel costs.~~be acquired is expected in November 2023.

~~Key settlement terms include:~~

•PSCo will recover Winter Storm Uri deferred net natural gas, fuel and purchased energy costs (prior to the $8 million disallowance) of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with no carrying charges through a rider mechanism.

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

•PSCo agreed to forego recovery of $14 million for replacement power costs due to an extended outage at Comanche Unit 3 during 2020 (approved by the CPUC in February 2022 as part of the 2020 retail electric commodity adjustment settlement agreement).

•PSCo also agreed to not seek recovery of COVID-19 related bad debt expense, previously deferred as a regulatory asset, and recorded an additional $11 million of incremental bad debt expense for the period ended Dec. 31, 2021.

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

In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of ~~decoupling. See Colorado Partial Settlement disclosure above.~~ the 2020 decoupling refunds.

In April 2022, PSCo made its annual filing on this matter. In December 2022, the ALJ approved a settlement between PSCo, CPUC Staff and the UCA. In the first quarter of 2023, PSCo filed a petition for CPUC declaratory judgment to address the treatment of any expired balance under the 3% soft cap provisions. A decision is pending.

As of ~~June 30, 2022,~~March 31, 2023, PSCo has recognized a refund for Residential customers and a surcharge for small C&I customers based on 2020, 2021, 2022 and the first ~~and second quarters~~quarter of ~~2022~~2023 results.

Transmission Cost Adjustment — In ~~April~~December 2022, the CPUC suspended PSCo’s request for 2023 TCA rate changes. The CPUC Staff protested the TCA on the grounds that only projects resulting in new transmission should be included and no repair or replacement of existing infrastructure should be included. The CPUC consolidated the matter with the pending electric rate case for assessment.

ECA Fuel Recovery — In December 2022, PSCo ~~made~~filed its ~~annual filing.~~first quarter 2023 ECA Advice Letter, which sought to recover $123 million of under-recovered 2022 fuel costs over two quarters (instead of one quarter, as more typical). In ~~May 2022 the UCA filed a protest raising issues relating to the Winter Storm Uri settlement and the soft cap components of the decoupling program. On May 25,~~December 2022, the CPUC found ~~merit in UCA’s protest, suspended PSCo’s advice letter and referred the matter to the ALJ.~~

~~2019 Electric Rate Case Appeal~~ ~~— In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gains and losses on sales of assets and other items.~~ ~~In January 2022, the court issued its decision~~ that the ~~CPUC’s approach~~$123 million should be removed from the proposed ECA rates, and required PSCo to ~~gains~~file a separate application to recover these costs.

In February 2023, PSCo submitted an interim ECA filing which included $70 million of the 2022 under-recovered costs and ~~losses~~collections commenced on ~~certain sales~~March 1, 2023. The remaining $53 million of ~~assets was legally erroneous~~under-recovered costs consists of $25 million of ordinary fuel and ~~confiscatory~~purchased energy costs and $28 million costs attributable to coal curtailments resulting from rail transportation labor shortages. PSCo expects to make filings in the second quarter regarding the prudence of costs associated with coal curtailments, and ~~set aside~~to request that recovery of the remaining $25 million of ordinary fuel and ~~remanded the issue for further consideration. The CPUC is expected to deliberate~~purchased energy costs commence in the third ~~quarter of 2022.~~quarter.

GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The CPUC has ~~reopened the GCA NOPR matter and~~ proposed a ~~2 step~~2-step process aimed at 1) considering near term process changes to the GCA ~~used by various utilities~~ and 2) a ~~longer term~~longer-term process to evaluate potential performance incentive ~~GCA structures to be filed by Nov. 1, 2022.~~structures. In step 1, consensus proposed rule amendments to update the process and filing requirements for GCA and related filings have been submitted to the CPUC for consideration. PSCo worked with other utilities and stakeholders regarding consensus proposed rule amendments for step 2, including a provision that each LDC bring forward its own PIM in a future filing. In December 2022, the CPUC approved the consensus proposal. PSCo expects to file its proposed PIM in the second quarter of 2023.

In February 2023, the Governor of Colorado issued an open letter to the CPUC, utilities and other stakeholders directing agencies to take additional steps to address energy costs. It is likely this request will result in the opening of additional dockets to further explore the GCA and other related mechanisms. Additionally, the Colorado Legislature formed a Joint Select Committee to investigate the source of rising utility rates and explore potential actions to prevent future price instability. Legislation has been introduced by members of the Joint Select Committee on a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).

Natural Gas Planning ~~NOPR~~ — In ~~October 2021,~~ the ~~CPUC~~first quarter of 2023, final rules were issued ~~a NOPR~~ to implement recent state legislation requiring natural gas utilities to develop clean heat plans ~~as a means~~ to meet state greenhouse gas emission reduction targets, as well as updated demand-side management criteria. Additionally, the ~~proposed~~ rules included new comprehensive natural gas infrastructure planning requirements and ~~related CPCN~~Certificate of Public Convenience and Necessity application procedures, changes in natural gas line extension policy, and details on emission accounting related to clean heat plans.

Real-Time Energy Imbalance Market — In April 2023, PSCo joined the SPP Western Energy Imbalance Service market which balances generation and load regionally and in real time for participants in the Western Interconnection. PSCo’s participation in the SPP Western Energy Imbalance Service market replaces its joint dispatch agreement while extending the geographic area for which energy sales are made.

SPS

Pending and Recently Concluded Regulatory Proceedings

SPS — 2022 New Mexico Electric Rate Case — In November 2022, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $78 million, or 10%. The request is based on a FTY ending June 30, 2024, a ROE of 10.75%, an equity ratio of 54.7% and rate base of $2.4 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2032 to 2028. In March 2023, the NMPRC issued an Order extending the suspension period by one month. Additionally, SPS filed a supplemental filing, which decreased the requested increase to $76 million.

On April 21, 2023, the following parties filed testimony: NMPRC Staff, OPL, AG, NMLCG, LES-FEA and Walmart, with all except Walmart providing a proposed revenue change.


(Millions of Dollars)	NMPRC Staff		OPL		AG		NMLCG		LES-FEA
SPS direct testimony	$	76	$	76	$	76	$	76	$	76

Recommended base rate adjustments:
Test year present revenues and allocators	(1)		2		(1)		1		(47)
ROE (a)	(24)		(29)		(37)		(29)		(21)
Capital structure	—		(22)		—		(22)		—
Adjustment to FTY plant additions/rate base items	—		(4)		(10)		(5)		—
Tolk Generating Station depreciation expense	—		(7)		—		(7)		(11)




Other, net	(14)		(1)		(19)		(13)		—
Total adjustments	(39)		(61)		(67)		(75)		(79)
Total proposed revenue change	$	37	$	15	$	9	$	1	$	(3)

(a)AG recommends a reduction of $37 million reflecting its combined recommendation for ROE and capital structure.


Recommended Position	NMPRC Staff		OPL		AG		NMLCG		LES-FEA		Walmart
ROE	9.35	%	8.70	%	9.00	%	8.70	%	9.40	%	9.61	%
Equity Ratio	54.70		45.00		50.57		45.00		54.70		N/A

The next steps in the revised procedural schedule are as follows:

•Rebuttal testimony: May 10, 2023.

•Stipulation: May 17, 2023.

•Hearing: June 20, 2023.

•End of rate suspension: Oct. 19, 2023.

2023 Texas Electric Rate Case — In February 2023, SPS filed an electric rate case with the Public Utility Commission of Texas (PUCT) seeking an increase in base rate revenue of $149 million (13%). In March 2023, SPS updated the filing based on a historical test year period ended Dec. 31, 2022, which increased the rate revenue request to $158 million (14% impact to customer bills). The request is based on a ROE of 10.65%, an equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the request reflects further acceleration of the Tolk coal plant depreciation life from 2034 to 2028. SPS is requesting a surcharge from July 13, 2023 through the effective date of new base rates.

Next steps in the procedural schedule are as follows:

•Intervenor direct testimony: August 4, 2023.

•Staff direct testimony: August 11, 2023.

•Rebuttal testimony: August 25, 2023.

•Hearings: Sept. 12-21, 2023.

•Proposed findings: Oct. 25, 2023.

A PUCT decision is expected in the first quarter of 2024.

SPS and LP&L Contract Termination — SPS and LP&L have a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (to the benefit of SPS’ remaining customers). LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The agreement has received PUCT approval and is pending FERC approval.

2022 All-Source RFP — In 2022, SPS issued an RFP, which seeks up to 947 MW of new or existing capacity resources to provide replacement capacity for retiring units and meet SPS’ growing capacity needs through 2027. SPS has received bids and is currently reviewing the proposals. SPS will file for the approval of successful proposals in the third quarter of 2023.

Texas Fuel Reconciliation — In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million. In April 2022, interim rates designed to recover $121 million over 30 months were approved, subject to PUCT approval through the triennial Fuel Reconciliation proceeding.

In November 2022, the ALJs found that costs were prudently incurred and recommended no disallowances. In March 2023, the PUCT issued a Final Order which fully adopted the recommended decision with no disallowances of costs.

~~SPS~~

~~Pending and Recently Concluded Regulatory Proceedings~~

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

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

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

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

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


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

Other

Supply Chain

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

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

Supply chain issues associated with semi-conductors have delayed the availability of advanced ~~metering~~ infrastructure ~~electric meters. Impacts~~meters, which led to a reduced number of meters deployed in 2022. While we have seen improvements in the 2023 deployment plan, the supply chain challenges persist. Full 2023 impacts and mitigation plans are currently being ~~evaluated~~evaluated.

Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases may result in delays in projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the ~~2022~~future. Xcel Energy continues to seek alternative suppliers and ~~2023 deployment schedule could be impacted.~~prioritize work plans to mitigate impacts of supply constraints.

Solar Resources

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

~~Uncertainty of the investigation and the adverse impact~~An interim stay on ~~potential~~ tariffs has ~~resulted~~been issued and many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action, a change in the ~~cancellation~~interim stay of tariffs, or ~~delay of certain domestic~~other restrictions on solar ~~projects.~~

~~The impacts on Xcel Energy are~~imports (i.e., as ~~follows:~~

•~~NSP-Minnesota Sherco Solar Project~~— In April 2021, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an initial estimated investment of approximately $575 million. NSP-Minnesota requested a delay in the procedural schedule due to recent solar supply chain disruptions and potential impact on pricing. An updated request was filed with the MPUC in July 2022 and a decision is now anticipated in the fourth quarter of 2022 or the first quarter of 2023. The proposed facilities are still expected to be in-service by the end of 2025.

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

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

Marshall Wildfire

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

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

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

~~Comanche Unit 3 Outage —In late January 2022, PSCo experienced an outage at~~ An evidentiary hearing regarding our request to dismiss Xcel Energy, Inc. from the ~~Comanche Unit 3 coal plant.The plant returned to service in June 2022. PSCo will not seek recovery of the approximately $18 million of incremental replacement power costs, subject to true-up, incurred during the outage.~~

~~Colorado Ballot Initiative —~~ In April 2022, a proposed ballot initiative was filed in the state of Colorado, which if approved, would require at least 5% of all gas and electric rates to be paid from profits as determined by the CPUC. At the end of April 2022, the initiative was approved by the Colorado Title Boardsuit is scheduled for ~~petition. If the petitioners receive 125,000 voter signatures by August 8, 2022, this initiative will be added to the ballot for the Colorado general election in November.~~May 2023.

MISO Capacity Credits — The NSP System offered 1,500 MW of excess capacity into the MISO planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing and is expected to generate revenues of approximately ~~$89~~$90 million in 2022 and approximately ~~$64~~$60 million in 2023. During the ~~second quarter of 2022,~~three months ended March 31, 2023, the NSP System received approximately ~~$13~~$40 million of capacity credits. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.

~~Winter Storm Uri~~

In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).

~~Regulatory Overview —~~Xcel Energy has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 63 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers. Xcel Energy currently has approval for recovery of Winter Storm Uri costs in Wisconsin, Michigan, North Dakota and New Mexico. There were no material costs for South Dakota.

~~A summary of the pending regulatory requests for Winter Storm Uri cost recovery in the other states is listed below.~~

~~Proceedings initiated:~~


~~Utility Subsidiary~~	~~Jurisdiction~~	~~Regulatory Status~~
~~NSP-Minnesota~~	~~Minnesota~~	In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, with a potential true-up pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period. The Department of Commerce recommended a disallowance of $122 million, the Office of the Attorney General recommended disallowances of $110 million to $148 million and the CUB recommended a $69 million disallowance. ~~In May 2022, the ALJs found the Winter Storm Uri fuel costs were prudently incurred and recommended no disallowances. A MPUC decision is expected in August 2022.~~


~~Utility Subsidiary~~	~~Jurisdiction~~	~~Regulatory Status~~
~~PSCo~~	~~Colorado~~	In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge. In October, a partial settlement was reached with the Staff and the Colorado Energy Office, allowing full recovery of the Winter Storm Uri costs over a 24-month (electric) and 30-month period (natural gas), with no carrying charges. In May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved the partial settlement, but included an $8 million disallowance.
~~SPS~~	~~Texas~~	~~In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million.~~ In April 2022, interim rates designed to recover $121 million over 30 months were implemented. The interim rate recovery does not address the prudence of costs nor the retention of approximately $10 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision. In July 2022, the intervenors filed recommendations in the Fuel Reconciliation proceeding. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins). ~~A hearing is scheduled to begin in August and a recommendation from the ALJ is expected in the fourth quarter of 2022.~~

Environmental

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

NOx Allowance Allocations —In ~~July 2019,~~March 2023, after disapproving state implementation plans, the EPA ~~adopted~~released a prepublication version of the ~~ACE rule, which requires states to develop plans by 2022 for greenhouse gas reductions from coal-fired power plants. In January 2021,~~final regulations under the ~~U.S. Court~~"Good Neighbor" provisions of Appeals for the D.C. Circuit issued a decision vacating and remanding the ACE rule. That decision essentially held that EPA’s previous economy-wide regulatory approach taken in the 2015 CPP was consistent with the Clean Air Act. ~~If upheld,~~The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. The rule establishes an allowance trading program for NOx that ~~decision~~will impact Xcel Energy fossil fuel-fired electric generating facilities in the states within our service territory. Applicable facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. Guidelines are also established for allowance banking and emission limit backstops.

While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms.

SPS and NSP-Minnesota have ~~allowed~~joined other impacted companies in litigation challenging the EPA’ disapproval of Texas and Minnesota state implementation plans.

GHG Emissions Limits — It is anticipated the EPA will propose rules to proceed with alternate regulation of coal-fired power plants consistent with the CPP approach. However, the Court of Appeals decision was appealed to the U.S Supreme Court. In a June 30, 2022, ruling, the Supreme Court held that a CPP economy-wide approach is not consistent with thelimit GHG emissions from new fossil fuel-fired electric generating units and natural gas-fired stationary combustion units under Clean Air ~~Act. Thus, if EPA is~~Act Section 111(b) as well as emission guidelines under Clean Air Act Section 111(d) to ~~proceed with new rules, they must be consistent with this ruling and be more similar to the ACE rule “inside the fenceline” approach.~~ limit GHG emissions from existing fossil fuel-fired electric generating units in 2023.

If any new rules require additional investment, Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

Coal Ash Regulation

In February 2023, the EPA entered into a Consent Decree committing the agency to either issue new proposed rules by May 5, 2023, to regulate inactive CCR landfills under the CCR Rule for the first time or to determine no such rules are necessary by that date.

If proposed rules are issued, the EPA has committed to a May 2024 effective date for those new rules. It is also anticipated that the EPA may issue other CCR proposed rules in 2023 that further expand the scope of

the CCR Rule. Until proposed rules are issued, it is not certain what the impact will be on Xcel Energy.

Emerging Contaminants of Concern

PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS but because PFAS are so ubiquitous in products and the environment, it may impact our operations.

In September 2022, the EPA proposed to designate two types of PFAS as “hazardous substances” under the CERCLA.

In March 2023, the EPA published a proposed rule that would establish enforceable drinking water standards for certain PFAS chemicals.

The proposed rules could result in new obligations for investigation and cleanup. Xcel Energy is monitoring changes to state laws addressing PFAS. The impact of these proposed regulations is uncertain.

Effluent Limitation Guidelines

In March 2023, the EPA released a proposed rule under the Clean Water Act, setting forth proposed Effluent Limitations Guidelines and Standards for steam generating coal plants. This proposed rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Comments to the proposed regulations are due May 30, 2023. The impact of these proposed regulations is uncertain.


Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value offor a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

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

Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform ~~under~~on the contracts underlying ~~its~~our derivatives, the contracts expose us to ~~some~~ credit and non-performance risk.

Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension ~~fund and Xcel Energy’s ability to earn a return on short-term investments.~~fund.

Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into ~~long-~~long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.

Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

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

Fair value of net commodity trading contracts as of ~~June 30, 2022:~~March 31, 2023:


		Futures / Forwards Maturity											Futures / Forwards Maturity
(Millions of Dollars)	(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (a)	NSP-Minnesota (a)	$	(4)	$	(12)	$	(5)	$	(3)	$	(24)	NSP-Minnesota (a)	$	(2)	$	(3)	$	(6)	$	(1)	$	(12)
NSP- Minnesota (b)	NSP- Minnesota (b)	3		5		(2)		(3)		3		NSP- Minnesota (b)	(2)		(7)		(2)		(2)		(13)
PSCo (a)	PSCo (a)	14		9		2		1		26		PSCo (a)	4		1		3		—		8
PSCo (b)	PSCo (b)	(33)		(39)		—		1		(71)		PSCo (b)	(42)		3		2		—		(37)
		$	(20)	$	(37)	$	(5)	$	(4)	$	(66)		$	(42)	$	(6)	$	(3)	$	(3)	$	(54)


		Options Maturity											Options Maturity
(Millions of Dollars)	(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value		(Millions of Dollars)	Less Than 1 Year		1 to 3 Years		4 to 5 Years		Greater Than 5 Years		Total Fair Value
NSP-Minnesota (b)	NSP-Minnesota (b)	$	3	$	—	$	—	$	11	$	14	NSP-Minnesota (b)	$	—	$	—	$	3	$	15	$	18
PSCo (b)	PSCo (b)	20		24		—		—		44		PSCo (b)	33		1		—		—		34
		$	23	$	24	$	—	$	11	$	58		$	33	$	1	$	3	$	15	$	52

~~At June 30, 2022, a~~A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts ~~through the forward curve~~ would ~~increase pre-tax~~have likewise increased and decreased pretax income from continuing operations, by an immaterial amount and approximately ~~$13~~$4 million ~~whereas a 10% decrease would decrease pre-tax income from continuing operations by~~at March 31, 2023, and approximately ~~$13 million. At June 30, 2021, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $19~~$14 million ~~whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $19 million.~~and $17 million at March 31, 2022. Market price movements can exceed 10% under abnormal circumstances.

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

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


(Millions of Dollars)	(Millions of Dollars)	Three Months Ended June 30		Average		High		Low		(Millions of Dollars)	Three Months Ended March 31		Average		High		Low
2023										2023	$	0.6	$	0.7	$	1.1	$	0.4
2022	2022	$	1.8	$	2.0	$	3.3	$	1.1	2022	1.1		1.0		1.3		0.7
2021		1.7		1.2		1.9		0.7

Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023, 2024 and ~~has its 2022 and 2023~~2025 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. ~~We will continue to monitor the evolving situation in Ukraine and its global impacts and will take necessary actions to ensure a secure supply of enriched nuclear material.~~ NSP-Minnesota is scheduled to take delivery of approximately ~~30%~~26% of its average enriched nuclear material requirements from Russia through 2030. Given the evolving situation in Ukraine and its global impacts, we have entered into additional new contracts that cover potential supply interruptions of nuclear material from Russia.

Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate ~~derivatives such as swaps, caps, collars and put or call options.~~derivatives.

~~At June 30, 2022 and 2021, a 100-basis-point~~A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact ~~pre-tax~~pretax interest expense annually by approximately $2$11 million and ~~$18~~$12 million in March 31, 2023 and 2022, respectively.

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

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

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

~~Changes~~The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan ~~assets impact the value of~~assets. Xcel Energy’s ongoing pension and postretirement ~~plan assets and/or benefit costs.~~

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

At ~~June 30, 2022,~~March 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$86~~$37 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of ~~$73~~$36 million. At ~~June 30, 2021,~~March 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$64~~$39 million, while a decrease in prices of 10% would have resulted in aan decrease in credit exposure of ~~$24~~$28 million.

Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk ~~control,~~controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.

Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.


FAIR VALUE MEASUREMENTS

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

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

See ~~Note~~Notes 8 and 9 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.~~information.

~~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, 2022.

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


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Operating Cash Flows


(Millions of Dollars)	~~Six~~Three Months Ended ~~June 30~~March 31
Cash provided by operating activities — ~~2021~~2022	$	~~489~~1,140

Components of change — ~~2022~~2023 vs. ~~2021~~2022
Higher net income	3538
Non-cash transactions ~~(a)~~	~~106~~53
Changes in working capital ~~(b)~~	~~256~~211
Changes in net regulatory and other assets and liabilities	~~1,102~~95
Cash provided by operating activities — ~~2022~~2023	$	~~1,988~~1,537

~~(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 increased ~~$1,499~~$397 million for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 compared with the prior year. The increase was primarily due to the impact of decreasing natural gas prices on customer receivables and accounts payable, as well as continued collections of deferred net natural gas, fuel and purchased energy costs ~~related to~~incurred during Winter Storm ~~Uri in the first quarter of 2021.~~Uri.

Investing Cash Flows


(Millions of Dollars)	~~Six~~Three Months Ended ~~June 30~~March 31
~~Cash used in investing activities — 2021~~	$	~~(2,202)~~

~~Components of change — 2022 vs. 2021~~
~~Increased capital expenditures~~	~~(73)~~

~~Other investing activities~~	~~220~~
Cash used in investing activities — 2022	$	~~(2,055)~~(952)

Components of change — 2023 vs. 2022
Increased capital expenditures	(323)

Other investing activities	(9)
Cash used in investing activities — 2023	$	(1,284)

Net cash used in investing activities ~~decreased $147~~increased $332 million for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 compared with the prior year. The increase in capital expenditures was largely due to ~~timing and normal~~continued system expansion.

Financing Cash Flows


(Millions of Dollars)	~~Six~~Three Months Ended ~~June 30~~March 31
Cash ~~provided by~~used in financing activities — ~~2021~~2022	$	~~2,122~~ (264)

Components of change — ~~2022~~2023 vs. ~~2021~~2022
Higher net short-term debt ~~repayments~~proceeds	~~(2,030)~~275
~~Higher~~Lower net long-term debt ~~issuances, net of~~ repayments	44 (250)
Higher proceeds from issuance of common stock	~~140~~5

Other financing activities	~~(40)~~(16)
Cash ~~provided by~~used in financing activities — ~~2022~~2023	$	~~236~~ (250)

Net cash ~~provided~~used by financing activities decreased ~~$1,886~~$14 million for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 compared with the prior year. The decrease was ~~primarily~~largely related to the amount/timing of debt issuances and ~~repayments associated with Winter Storm Uri.~~repayments.

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

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

•In ~~2021,~~2022, contributions of ~~$131~~$50 million were made across four of Xcel Energy’s pension plans.

•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.

Capital Sources

Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.

Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of ~~the~~their revolving credit facility termination date for two additional one-year periods beyond the ~~June 2024~~September 2027 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

As of ~~July 25, 2022,~~April 24, 2023, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:


(Millions of Dollars)	(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity		(Millions of Dollars)	Credit Facility (a)		Drawn (b)		Available		Cash		Liquidity
Xcel Energy Inc.	Xcel Energy Inc.	$	1,250	$	73	$	1,177	$	5	$	1,182	Xcel Energy Inc.	$	1,500	$	367	$	1,133	$	1	$	1,134
PSCo	PSCo	700		196		504		2		506		PSCo	700		27		673		155		828
NSP-Minnesota	NSP-Minnesota	500		11		489		2		491		NSP-Minnesota	700		92		608		4		612
SPS	SPS	500		2		498		5		503		SPS	500		55		445		2		447
NSP-Wisconsin	NSP-Wisconsin	150		86		64		1		65		NSP-Wisconsin	150		30		120		1		121
Total	Total	$	3,100	$	368	$	2,732	$	15	$	2,747	Total	$	3,550	$	571	$	2,979	$	163	$	3,142

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

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

~~Bilateral Credit Agreement~~

~~In April 2022, NSP-Minnesota’s uncommitted $75 million bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.~~

~~As of June 30, 2022, NSP-Minnesota had $43 million of outstanding letters of credit under the $75 million bilateral credit agreement.~~

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

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

•$700 million for PSCo.

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

•$500 million for SPS.

•$150 million for NSP-Wisconsin.

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

(Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2022 Year Ended Dec. 31, 2021
Borrowing limit $ 3,100 $ 3,100
Amount outstanding at period end 136 1,005
Average amount outstanding 554 1,399
Maximum amount outstanding 1,136 2,054
Weighted average interest rate, computed on a daily basis 1.05 % 0.57 %
Weighted average interest rate at period end 1.90 0.31

Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.

Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.

~~2022~~2023 Planned Financing Activity — During ~~2022,~~2023, Xcel Energy ~~Inc.~~ plans to issue ~~approximately $75 to $80~~approximately $85 million of equity through the DRIP and benefit ~~programs. In addition,~~programs. Xcel Energy ~~Inc. may issue up to $800 million in equity from 2022-2026. In 2022, approximately $150 million of equity has been issued through an ATM program. Xcel Energy Inc.~~ and its utility subsidiaries issued or plan to issue the following long-term debt:

Issuer

Security

Amount

Status

Tenor

Coupon

Issuer

Security

Amount

Status

Tenor

Coupon

PSCo

First Mortgage Bonds

850

million

Completed (a)

30 Year

5.25%

NSP-Wisconsin

First Mortgage Bonds

125

million

Second Quarter (b)

30 Year

5.30

NSP-Minnesota

First Mortgage Bonds

800

million

Second Quarter

N/A

Xcel Energy

Unsecured Senior Notes

700

million

Completed

10 Year

4.60%

Xcel Energy

Unsecured Senior Notes

500

million

Third Quarter

N/A

PSCo

First Mortgage Bonds

300

million

Completed

10 Year

4.10%

PSCo

First Mortgage Bonds

400

million

Completed

30 Year

4.50%

SPS

First Mortgage Bonds

200

million

Completed

30 Year

5.15%

SPS

First Mortgage Bonds

100

million

Third Quarter

N/A

NSP-Minnesota

First Mortgage Bonds

500

million

Completed

30 Year

4.50%

NSP-Wisconsin

First Mortgage Bonds

100

million

Q3 (a)

30 Year

4.86%

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

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

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

•Constructive outcomes in all rate case and regulatory proceedings.

•Normal weather patterns for the remainder of the year.

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

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

•Capital rider revenue is projected to increase $0$70 million to ~~$10~~$80 million (net of PTCs). The change from the previous estimate is largely due to a change in the projected levels of PTCs, which are offset in the ETR and largely earnings neutral.

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

•Depreciation expense is projected to increase approximately ~~$300~~$130 million to ~~$310~~$140 million. ~~The change in assumption is primarily a result of new rates going into effect in Texas and will be offset by revenue with minimal impact on earnings.~~

•Property taxes are projected to increase approximately ~~$35~~$30 million to ~~$45~~$40 million.

•Interest expense (net of AFUDC - debt) is projected to increase $100 million to $110 million. ~~The assumption change reflects higher interest rates and slightly larger debt issuances.~~

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

•ETR is projected to be ~(6%7%) to ~~(8%~~(9%). The change from the previous estimate is largely due to a change in the projected levels of PTCs, which are offset in the capital riders and fuel mechanisms and are largely earnings neutral.

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

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

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

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

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

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


ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, ~~2021~~2022 under “Derivatives, Risk Management and Market Risk.”


ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

As of ~~June 30, 2022,~~March 31, 2023, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

PART II — OTHER INFORMATION


ITEM 1 — LEGAL PROCEEDINGS

Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.

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

For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. 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, ~~2021,~~2022, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.


Class						Outstanding at ~~July 21, 2022~~April 24, 2023
Common Stock, $2.50 par value						~~546,991,330~~550,356,331 shares


PART I	FINANCIAL INFORMATION
Item 1 —	Financial Statements (unaudited)	45
	Consolidated Statements of Income	45
	Consolidated Statements of Comprehensive Income	56
	Consolidated Statements of Cash Flows	67
	Consolidated Balance Sheets	78
	Consolidated Statements of Common Stockholders’ Equity	89
	Notes to Consolidated Financial Statements	910
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2120
Item 3 —	Quantitative and Qualitative Disclosures A bout Market Risk	3230
Item 4 —	Controls and Procedures	3230

PART II	OTHER INFORMATION
Item 1 —	Legal Proceedings	3230
Item 1A —	Risk Factors	3230
Item 2 —	Unregistered Sales of Equity Securities and Use of Proceeds	3231
Item 6 —	Exhibits	3331

SIGNATURES		3432


		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, 2022 and 2021
Balance at March 31, 2021		538,076,662	$	1,345	$	7,411	$	6,082	$	(138)	$	14,700

														Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
														Shares	Par Value		Additional Paid In Capital
Three Months Ended March 31, 2023 and 2022													Three Months Ended March 31, 2023 and 2022
Balance at Dec. 31, 2021													Balance at Dec. 31, 2021	544,025,269	$	1,360	$	7,803	$	6,572	$	(123)	$	15,612
Net income	Net income						311				311		Net income						380				380
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

Balance at March 31, 2022		544,530,987	$	1,361	$	7,801	$	6,686	$	(116)	$	15,732
Net income							328				328
Other comprehensive income									13		13
Other comprehensive loss													Other comprehensive loss								7		7
Dividends declared on common stock ($0.4875 per share)	Dividends declared on common stock ($0.4875 per share)						(266)				(266)		Dividends declared on common stock ($0.4875 per share)						(265)				(265)
Issuances of common stock	Issuances of common stock	2,276,806	6		153						159		Issuances of common stock	505,718	1		11						12

Share-based compensation	Share-based compensation				6		(1)				5		Share-based compensation				(13)		(1)				(14)
Balance at June 30, 2022		546,807,793	$	1,367	$	7,960	$	6,747	$	(103)	$	15,971

Balance at March 31, 2022													Balance at March 31, 2022	544,530,987	$	1,361	$	7,801	$	6,686	$	(116)	$	15,732
		Common Stock Issued					Retained Earnings		Accumulated Other Comprehensive Loss		Total Common Stockholders' Equity
		Shares	Par Value		Additional Paid In Capital
Six Months Ended June 30, 2022 and 2021
Balance at Dec. 31, 2020		537,438,394	$	1,344	$	7,404	$	5,968	$	(141)	$	14,575
Balance at Dec. 31, 2022													Balance at Dec. 31, 2022	549,578,018	$	1,374	$	8,155	$	7,239	$	(93)	$	16,675
Net income	Net income						673				673		Net income						418				418
Other comprehensive loss									6		6
Dividends declared on common stock ($0.915 per share)							(492)				(492)
Other comprehensive income													Other comprehensive income								(4)		(4)
Dividends declared on common stock ($0.52 per share)													Dividends declared on common stock ($0.52 per share)						(286)				(286)
Issuances of common stock	Issuances of common stock	867,533	2		28						30		Issuances of common stock	644,174	2		16						18

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

Balance at June 30, 2021		538,305,927	$	1,346	$	7,435	$	6,146	$	(135)	$	14,792

Balance at Dec. 31, 2021		544,025,269	$	1,360	$	7,803	$	6,572	$	(123)	$	15,612
Net income							708				708
Other comprehensive income									20		20
Dividends declared on common stock ($0.975 per share)							(531)				(531)
Issuances of common stock		2,782,524	7		164						171

Share-based compensation					(7)		(2)				(9)
Balance at June 30, 2022		546,807,793	$	1,367	$	7,960	$	6,747	$	(103)	$	15,971
Balance at March 31, 2023													Balance at March 31, 2023	550,222,192	$	1,376	$	8,169	$	7,370	$	(97)	$	16,818

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


(Millions of Dollars)	(Millions of Dollars)	June 30, 2022		Dec. 31, 2021		(Millions of Dollars)	March 31, 2023		Dec. 31, 2022
Property, plant and equipment, net	Property, plant and equipment, net					Property, plant and equipment, net
Electric plant	Electric plant	$	48,445	$	48,680	Electric plant	$	50,227	$	49,639
Natural gas plant	Natural gas plant	8,029		7,758		Natural gas plant	8,612		8,514
Common and other property	Common and other property	2,769		2,602		Common and other property	3,001		2,970
Plant to be retired (a)	Plant to be retired (a)	2,310		1,200		Plant to be retired (a)	2,180		2,217
Construction work in progress	Construction work in progress	2,056		1,969		Construction work in progress	2,224		2,124
Total property, plant and equipment	Total property, plant and equipment	63,609		62,209		Total property, plant and equipment	66,244		65,464
Less accumulated depreciation	Less accumulated depreciation	(17,336)		(17,060)		Less accumulated depreciation	(17,694)		(17,502)
Nuclear fuel	Nuclear fuel	3,096		3,081		Nuclear fuel	3,266		3,183
Less accumulated amortization	Less accumulated amortization	(2,834)		(2,773)		Less accumulated amortization	(2,920)		(2,892)
Property, plant and equipment, net	Property, plant and equipment, net	$	46,535	$	45,457	Property, plant and equipment, net	$	48,896	$	48,253


☒			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)


	Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)	Accumulated Other Comprehensive Loss		Regulatory ~~(Assets)~~Assets and Liabilities









Three Months Ended ~~June 30, 2022~~March 31, 2023
Derivatives designated as cash flow hedges:
Interest rate	$	15 (7)	$	—
Total	$	15 (7)	$	—
Other derivative instruments:
Electric commodity	$	—	$	98 (92)
Natural gas commodity	—		~~(1)~~3
Total	$	—	$	97 (89)











~~Six~~Three Months Ended ~~June 30,~~March 31, 2022
Derivatives designated as cash flow hedges:
Interest rate	$	226	$	—
Total	$	226	$	—
Other derivative instruments:
Electric commodity	$	—	$	~~100~~1
Natural gas commodity	—		34
Total	$	—	$	~~103~~


~~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~~	$	—	$	135


(Millions of Dollars)	Three Months Ended June 30, 2022 vs. 2021		Six Months Ended June 30, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)	$	124	$	187
Revenue recognition for the Texas rate case surcharge (a)	85		85
Sales and demand (b)	38		60
Non-fuel riders	7		41
Conservation and demand side management (offset in expense)	9		22

Estimated impact of weather (net of decoupling/sales true-up)	2		9
PTCs flowed back to customers (offset by lower ETR)	(50)		(103)
Proprietary commodity trading, net of sharing (c)	(8)		(33)
Comanche Unit 3 outage unrecovered purchased power cost (d)	(8)		(18)
Other (net)	(7)		(3)
Total increase	$	192	$	247


(Millions of Dollars)	Three Months Ended March 31, 2023 vs. 2022
Regulatory rate outcomes (Colorado and Wisconsin)	$	47
Estimated impact of weather	9

Infrastructure and integrity riders	4



Other (net)	4
Total increase	$	64


2022 Rate Request (Millions of Dollars)	Staff		UCA
Filed base revenue request	$	215	$	215
Less: previously authorized costs (existing riders)	108		108
Filed net increase to revenue	107		107

Recommended adjustments:
Test year adjustments	(33)		(41)
ROE	(42)		(42)




Weather normalization adjustment	—		(7)
Depreciation expense change	14		—
Other, net	(15)		(5)
Total recommended adjustments	(76)		(95)





Total proposed revenue change	$	31	$	12


(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2022			Year Ended Dec. 31, 2021
Borrowing limit	$	3,100		$	3,100
Amount outstanding at period end	136			1,005
Average amount outstanding	554			1,399
Maximum amount outstanding	1,136			2,054
Weighted average interest rate, computed on a daily basis	1.05		%	0.57		%
Weighted average interest rate at period end	1.90			0.31


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


Forward-Looking Statements


	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2023 - Jan. 31, 2023	—	$	—	—	—
Feb. 1, 2023 - Feb. 28, 2023	—	—		—	—
March 1, 2023 - March 31, 2023 (a)	795	64.57		—	—
	795			—	—


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012	Xcel Energy Inc. Form 8-K dated May 16, 2012	3.01
3.02*	Bylaws of Xcel Energy Inc. as Amended on April 3, 2020	Xcel Energy Inc Form 8-K dated April 3, 2020	3.01
4.01*	Supplemental Indenture No. ~~16,~~34 dated as of May 6, 2022, by and between Xcel Energy Inc. and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee, creating $700,000,000 aggregate principal amount of 4.60% Senior Notes, Series due JuneMarch 1, ~~2032~~	~~Xcel Energy Inc. Form 8-K dated May 6, 2022~~	~~4.01~~
~~4.02~~*	Supplemental Trust Indenture dated as of May 1, 2022 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $500,000,000 aggregate principal amount of 4.50% First Mortgage Bonds, Series due June 1, 2052	~~NSP-Minnesota Form 8-K dated May 9, 2022~~	~~4.01~~
~~4.03~~*	~~Supplemental Indenture dated as of May 1, 2022,~~2023, between PSCo and U.S. Bank Trust Company, National Association, as successor Trustee, creating ~~$300~~$850 million aggregate principal amount of ~~4.10%~~5.25% First Mortgage Bonds, Series No. 3840 due ~~2032 and $400 million principal amount of 4.50% First Mortgage Bonds, Series No. 39 due 2052~~April 1, 2053	PSCo Form 8-K dated ~~May 17, 2022~~April 3, 2023	4.01
~~4.04~~*	Supplemental Indenture No. 9 dated as of May 1, 2022 between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as trustee, creating $200 million principal amount of 5.15% First Mortgage Bonds, Series ~~No. 9~~ ~~due 2052~~	~~SPS Form 8-K dated May 31, 2022~~	~~4.02~~
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.

~~7/28/2022~~4/27/2023	By:	/s/ BRIAN J. VAN ABEL
		Brian J. Van Abel
		Executive Vice President, Chief Financial Officer
		(~~Duly Authorized~~Principal Accounting Officer and Principal Financial Officer)