Exhibit 99.01

	414 Nicollet Mall
10/27/2022	Minneapolis, MN 55401

XCEL ENERGY

THIRD QUARTER 2022 EARNINGS REPORT

•Third quarter GAAP diluted earnings per share were $1.18 in 2022 compared with $1.13 in 2021.

•Year-to-date GAAP diluted earnings per share for 2022 were $2.48 compared with $2.38 in 2021.

•Xcel Energy narrows its 2022 EPS guidance range to $3.14 to $3.19 from $3.10 to $3.20.

•Xcel Energy initiates 2023 EPS guidance of $3.30 to $3.40.

MINNEAPOLIS — Xcel Energy Inc. (NASDAQ: XEL) today reported 2022 third quarter GAAP and ongoing earnings of $649 million, or $1.18 per share, compared with $609 million, or $1.13 per share in the same period in 2021.

Earnings reflect capital investment recovery and other regulatory outcomes, partially offset by higher depreciation, interest expense and operating and maintenance (O&M) expenses.

“Xcel Energy had a strong third quarter – both operationally and financially – which has allowed us to narrow our 2022 earnings guidance to $3.14 to $3.19 per share,” said Bob Frenzel, chairman, president and CEO of Xcel Energy.

“This quarter also saw the passage of the groundbreaking Inflation Reduction Act, whose clean energy provisions will provide significant customer benefit, reduce the cost of the clean energy transition and improve our liquidity through tax credit transferability. As a result of the legislation, the cost of our recently approved 460-MW Sherco Solar project will be reduced by more than 30%. It will also lower the cost of 10,000 MWs of renewables that were approved as part of our Minnesota and Colorado resource plans and further enhance Xcel Energy’s and the region’s competitive advantage due to strong wind and solar resources in our states.”

At 9:00 a.m. CDT today, Xcel Energy will host a conference call to review financial results. To participate in the call, please dial in 5 to 10 minutes prior to the start and follow the operator’s instructions.

US Dial-In:	(866) 580-3963
International Dial-In:	(400) 120-0558
Conference ID:	0230649

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investors under Company. If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on Oct. 27 through 12:00 p.m. CDT on Oct. 31.

Replay Numbers
US Dial-In:	1 (866) 583-1035
Access Code:	0230649#

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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 and 2023 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2021 and subsequent filings with the Securities and Exchange Commission, 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, and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; regulatory changes and/or limitations related to the use of natural gas as an energy source; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters, including as a result of evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.

For more information, contact:

Paul Johnson, Vice President - Treasurer & Investor Relations	(612) 215-4535
For news media inquiries only, please call Xcel Energy Media Relations	(612) 215-5300

Xcel Energy website address: www.xcelenergy.com

This information is not given in connection with any

sale, offer for sale or offer to buy any security.

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in millions, except per share data)

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2022		2021		2022		2021
Operating revenues
Electric	$	3,699	$	3,176	$	9,255	$	8,643
Natural gas	357		268		1,923		1,364
Other	26		23		79		69
Total operating revenues	4,082		3,467		11,257		10,076
Operating expenses
Electric fuel and purchased power	1,497		1,210		3,772		3,643
Cost of natural gas sold and transported	173		86		1,134		603
Cost of sales — other	11		11		32		28
O&M expenses	611		568		1,827		1,752
Conservation and demand side management expenses	86		78		259		222
Depreciation and amortization	607		537		1,807		1,586
Taxes (other than income taxes)	173		152		523		472
Total operating expenses	3,158		2,642		9,354		8,306
Operating income	924		825		1,903		1,770
Other (expense) income, net	(15)		(3)		(20)		5
Earnings from equity method investments	1		13		27		47
Allowance for funds used during construction — equity	20		21		53		53
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $7, $24 and $22, respectively	244		211		705		628
Allowance for funds used during construction — debt	(7)		(7)		(19)		(18)
Total interest charges and financing costs	237		204		686		610
Income before income taxes	693		652		1,277		1,265
Income tax expense (benefit)	44		43		(80)		(17)
Net income	$	649	$	609	$	1,357	$	1,282
Weighted average common shares outstanding:
Basic	548		539		546		539
Diluted	548		539		546		539
Earnings per average common share:
Basic	$	1.19	$	1.13	$	2.48	$	2.38
Diluted	1.18		1.13		2.48		2.38

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Investor Relations Earnings Release (Unaudited)

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as certain non-GAAP financial measures such as ongoing return on equity (ROE), 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.

Ongoing ROE

Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain

nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and

provide details of earnings results.

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

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Note 1. Earnings Per Share Summary

Xcel Energy’s third quarter diluted earnings were $1.18 per share in 2022, compared with $1.13 per share in 2021. The increase was driven by regulatory rate outcomes, partially offset by higher depreciation, interest charges and O&M expenses. Costs for natural gas significantly increased in 2022 due to supply and demand conditions. However, fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

Summarized diluted EPS for Xcel Energy:

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share	2022		2021		2022		2021
PSCo	$	0.45	$	0.40	$	1.02	$	0.96
NSP-Minnesota	0.49		0.46		0.94		0.91
SPS	0.25		0.25		0.52		0.48
NSP-Wisconsin	0.07		0.07		0.19		0.15
Earnings from equity method investments — WYCO	0.01		0.01		0.03		0.03
Regulated utility (a)	1.28		1.19		2.69		2.54
Xcel Energy Inc. and Other	(0.09)		(0.06)		(0.21)		(0.16)
Total (a)	$	1.18	$	1.13	$	2.48	$	2.38

(a) Amounts may not add due to rounding.

PSCo — Earnings increased $0.05 per share for the third quarter of 2022 and $0.06 year-to-date. Higher year-to-date earnings reflect regulatory rate outcomes, partially offset by increased depreciation and O&M expenses.

NSP-Minnesota — Earnings increased $0.03 per share for the third quarter of 2022 and year-to-date. The year-to-date increase is primarily due to regulatory rate outcomes, partially offset by increased depreciation, O&M expenses and a Winter Storm Uri cost disallowance (see Note 5).

SPS — Earnings were flat for the third quarter of 2022 and increased $0.04 per share year-to-date. Higher year-to-date earnings largely reflect regulatory rate outcomes, strong sales growth and favorable weather, partially offset by higher depreciation, O&M expenses and interest charges.

NSP-Wisconsin — Earnings were flat for the third quarter of 2022 and increased $0.04 per share year-to-date. The year-to-date increase is due to regulatory rate outcomes and sales growth, 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 (EIP) funds equity method investments. Earnings decreased $0.05 per share year-to-date, largely attributable to higher interest charges.

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

Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30		Nine Months Ended Sept. 30
GAAP and ongoing diluted EPS — 2021	$	1.13	$	2.38
Components of change - 2022 vs. 2021
Higher electric revenues, net of electric fuel and purchased power	0.33		0.67
Lower effective tax rate (ETR) (a)	0.02		0.12
Higher natural gas revenues, net of cost of natural gas sold and transported	—		0.04
Higher depreciation and amortization	(0.10)		(0.30)
Higher O&M expenses	(0.06)		(0.10)
Higher interest charges	(0.04)		(0.10)
Higher taxes (other than income taxes)	(0.03)		(0.07)
Lower other (expense) income	(0.02)		(0.03)
Other, net	(0.05)		(0.13)
GAAP and ongoing diluted EPS — 2022	$	1.18	$	2.48

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

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Note 2. Regulated Utility Results

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 mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric utility in those jurisdictions.

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.

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

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2022 vs. Normal		2021 vs. Normal		2022 vs. 2021		2022 vs. Normal		2021 vs. Normal		2022 vs. 2021
Retail electric	$	0.074	$	0.067	$	0.007	$	0.123	$	0.122	$	0.001
Decoupling and sales true-up	(0.032)		(0.035)		0.003		(0.055)		(0.076)		0.021
Electric total	$	0.042	$	0.032	$	0.010	$	0.068	$	0.046	$	0.022
Firm natural gas	—		—		—		0.019		0.004		0.015
Total	$	0.042	$	0.032	$	0.010	$	0.087	$	0.050	$	0.037

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

	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	(1.7)	%	(2.7)	%	7.8	%	(0.1)	%	(0.7)	%
Electric C&I	(2.3)		0.2		7.2		3.7		1.6
Total retail electric sales	(2.0)		(0.8)		7.3		2.6		0.9
Firm natural gas sales	(1.6)		—		N/A		2.3		(0.9)

	Three Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(4.6)	%	0.5	%	3.3	%	(0.1)	%	(1.1)	%
Electric C&I	(3.2)		0.4		6.4		3.5		1.2
Total retail electric sales	(3.7)		0.4		5.9		2.5		0.5
Firm natural gas sales	(1.5)		(2.2)		N/A		—		(1.6)

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

	Nine Months Ended Sept. 30
	PSCo		NSP-Minnesota		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	(3.7)	%	0.6	%	0.7	%	0.6	%	(1.0)	%
Electric C&I	(0.5)		2.7		9.0		3.8		3.5
Total retail electric sales	(1.6)		2.0		7.4		2.8		2.2
Firm natural gas sales	(2.4)		6.0		N/A		7.4		0.9

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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% increase in customers. C&I sales decline was attributable to decreased use per customer, primarily in the manufacturing sector (largely due to an alternative generation arrangement with a significant customer), partially offset by strong small C&I sales in the professional services and health care sectors.

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

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

•NSP-Wisconsin — Residential sales growth was driven by a 0.7% increase in customers. C&I sales growth was primarily associated with higher use per customer, experienced primarily in the transportation and manufacturing sectors.

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

•Natural gas sales reflect a higher use per customer, experienced primarily in NSP-Minnesota and NSP-Wisconsin, partially offset by a decrease in PSCo (lower residential use per customer). In addition, residential and C&I customer growth was 1.2% and 0.5%, respectively.

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

Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact due to fuel recovery mechanisms that recover fuel expenses. 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:

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

(Millions of Dollars)	Three Months Ended Sept. 30, 2022 vs. 2021		Nine Months Ended Sept. 30, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)	$	165	$	361
Revenue recognition for the Texas rate case surcharge (a)	—		85
Sales and demand (b)	24		84
Non-fuel riders	8		48
Conservation and demand side management (offset in expenses)	9		31
Wholesale transmission (net)	19		25
Estimated impact of weather (net of decoupling/sales true-up)	7		16
PTCs flowed back to customers (offset by lower ETR)	(17)		(120)
Proprietary commodity trading, net of sharing (c)	(1)		(33)
Other (net)	22		(14)
Total increase	$	236	$	483

(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.

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

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

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

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

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

(Millions of Dollars)	Three Months Ended Sept. 30, 2022 vs. 2021		Nine Months Ended Sept. 30, 2022 vs. 2021
Regulatory rate outcomes (Minnesota, Wisconsin, North Dakota, Colorado)	$	2	$	16
Estimated impact of weather	—		11
Conservation revenue (offset in expenses)	2		9
Infrastructure and integrity riders	4		7
Winter Storm Uri disallowances (see Note 5)	(7)		(20)
Other (net)	1		5
Total increase	$	2	$	28

O&M Expenses — O&M expenses increased $43 million for the third quarter and $75 million year-to-date. O&M costs increased due to recognition of previously deferred amounts related to the 2021 Texas Electric Rate Case, additional investments in technology and customer programs, higher costs for storms and vegetation management and inflationary impacts. These increases were partially offset by a reduction in employee benefit costs and timing of certain power plant overhaul costs.

Depreciation and Amortization — Depreciation and amortization increased $70 million for the third quarter and $221 million year-to-date. The increase was primarily driven by normal system expansion, recognition of previously deferred costs related to the Texas Electric Rate Case and several wind farms going into service.

Other (Expense) Income — Other (expense) income decreased $12 million for the third quarter and $25 million year-to-date, largely related to rabbi trust performance, which is primarily offset in O&M expenses (employee benefit costs).

Interest Charges — Interest charges increased $33 million for the third quarter and $77 million year-to-date, largely due to higher interest rates and increased long-term debt levels to fund capital investments.

Income Taxes — Effective income tax rate:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2022		2021		2022 vs 2021		2022		2021		2022 vs 2021
Federal statutory rate	21.0	%	21.0	%	—	%	21.0	%	21.0	%	—	%
State tax (net of federal tax effect)	4.9		5.0		(0.1)		4.9		5.0		(0.1)
(Decreases) increases:
Wind PTCs (a)	(12.3)		(12.1)		(0.2)		(25.2)		(20.0)		(5.2)
Plant regulatory differences (b)	(5.8)		(5.8)		—		(5.5)		(6.0)		0.5
Other tax credits, net operating loss & tax credits allowances	(1.2)		(1.2)		—		(1.4)		(1.1)		(0.3)
Other (net)	(0.3)		(0.3)		—		(0.1)		(0.2)		0.1
Effective income tax rate	6.3	%	6.6	%	(0.3)	%	(6.3)	%	(1.3)	%	(5.0)	%

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

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

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Income tax expense increased $1 million for the third quarter and income tax benefit increased $63 million year-to-date. The year-to-date increase was primarily driven by an increase in wind PTCs due to greater production at existing wind farms, several new wind farms going into service and an increase in the PTC rate.

Inflation Reduction Act — In August 2022, the Inflation Reduction Act (IRA) was signed into law.

Key provisions impacting Xcel Energy include:

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

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

•Creates a PTC for solar, clean hydrogen and nuclear.

•Establishes an ITC for energy storage, microgrids, interconnection facilities, etc.

•Allows companies to monetize or sell credits to unrelated parties.

Xcel Energy anticipates the IRA will drive approximately $500 million of customer savings over the next 5 years for existing company owned renewable projects, assuming appropriate regulatory mechanisms and development of a market for the sale of credits. The IRA will drive additional customer savings as Xcel Energy adds new renewable projects due to the extension of tax credits and transferability.

The IRA is expected to allow Xcel Energy to monetize tax credits more efficiently with the incremental benefits passed through to customers. Transferability provisions apply to eligible tax credits generated starting in 2023 for both new and existing facilities. Xcel Energy anticipates tax credit transferability from existing renewable projects will improve cash from operations by $1.8 billion (2023-2027), assuming constructive regulatory outcomes and the development of a market. Tax credit transferability has been included in our five-year financing plan and rate base projections.

The IRA creates a nuclear PTC beginning in 2024 that may also provide additional customer savings. The annual customer benefit from these PTCs could range from $0 to $200 million, depending on locational marginal pricing, as well as constructive U.S. Treasury guidance regarding computation of the credits.

In addition, the IRA created a new corporate alternative minimum tax (AMT). Xcel Energy does not anticipate AMT having a material cash impact based on current estimates and our interpretation of AMT application.

Note 3. Capital Structure, Liquidity, Financing and Credit Ratings

Xcel Energy’s capital structure:

(Millions of Dollars)	Sept. 30, 2022		Percentage of Total Capitalization		Dec. 31, 2021		Percentage of Total Capitalization
Current portion of long-term debt	$	651	2	%	$	601	1	%
Short-term debt	158		—		1,005		3
Long-term debt	23,309		58		21,779		56
Total debt	24,118		60		23,385		60
Common equity	16,384		40		15,612		40
Total capitalization	$	40,502	100	%	$	38,997	100	%

Liquidity —As of Oct. 25, 2022, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

(Millions of Dollars)	Credit Facility(a)		Drawn(b)		Available		Cash		Liquidity
Xcel Energy Inc.	$	1,500	$	129	$	1,371	$	1	$	1,372
PSCo	700		264		436		3		439
NSP-Minnesota	700		55		645		4		649
SPS	500		67		433		1		434
NSP-Wisconsin	150		—		150		3		153
Total	$	3,550	$	515	$	3,035	$	12	$	3,047

(a)    Expires September 2027.

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

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Credit Ratings — Access to the capital markets at reasonable terms is partially dependent on credit ratings. The following ratings reflect the views of Moody’s, S&P Global Ratings and Fitch. The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries as of Oct. 25, 2022:

Credit Type	Company	Moody’s	S&P Global Ratings	Fitch
Senior unsecured debt	Xcel Energy Inc.	Baa1	BBB+	BBB+
Senior secured debt	NSP-Minnesota	Aa3	A	A+
	NSP-Wisconsin	Aa3	A	A+
	PSCo	A1	A	A+
	SPS	A3	A	A-
Commercial paper	Xcel Energy Inc.	P-2	A-2	F2
	NSP-Minnesota	P-1	A-2	F2
	NSP-Wisconsin	P-1	A-2	F2
	PSCo	P-2	A-2	F2
	SPS	P-2	A-2	F2

Capital Expenditures — Base capital expenditures and incremental capital forecasts for Xcel Energy for 2023 through 2027:

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

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

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

The base plan does not include any potential renewable generation assets approved in our Minnesota and Colorado resource plans or additional transmission capital needed to integrate new renewable generation additions in Colorado, beyond the Pathway project. We expect further clarification in the second half of 2023 after the commissions rule on the recommended resource plan portfolios, which could result in incremental capital expenditures of approximately $2 to $4 billion (assuming 50% ownership of the renewable projects).

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.

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Financing for Capital Expenditures through 2027 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Current estimated financing plans of Xcel Energy for 2023 through 2027 (includes the estimated impact of approximately $1.8 billion of tax credit transferability):

(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)	$	20,540
New debt (b)	8,210
Equity through the Dividend Reinvestment and Stock Purchase Program (DRIP) and benefit program	425
Other equity	325
Base capital expenditures 2023-2027	$	29,500
Maturing Debt	$	3,800

(a) Net of dividends and pension funding.

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

2022 Financing Activity — During 2022, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit programs. In 2022, approximately $150 million of equity has been issued through an at-the-market program. Xcel Energy and its utility subsidiaries issued the following long-term debt:

Issuer	Security	Amount		Tenor	Coupon
Xcel Energy	Unsecured Senior Notes	$	700	10 Year	4.60	%
PSCo	First Mortgage Bonds	300		10 Year	4.10
PSCo	First Mortgage Bonds	400		30 Year	4.50
SPS	First Mortgage Bonds	200		30 Year	5.15
NSP-Minnesota	First Mortgage Bonds	500		30 Year	4.50
NSP-Wisconsin	First Mortgage Bonds	100		30 Year	4.86

Financing plans are subject to change, depending on legislative initiatives (e.g., federal tax law changes), capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.

Note 4. Rates, Regulation and Other

NSP-Minnesota —2022 Minnesota Electric Rate Case— In 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 52.5% equity ratio and forward test years.

The request is detailed as follows:

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

In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. On Sept. 30, 2022, NSP-Minnesota requested an incremental increase to interim rates of $122 million, effective Jan. 1, 2023. On Oct. 21, 2022, intervening parties to the rate case filed comments recommending the MPUC deny NSP-Minnesota’s request. A MPUC decision is expected in late 2022.

In October 2022, nine parties filed testimony. The Minnesota Department of Commerce (DOC), Office of Attorney General (OAG), Xcel Large Industrial Customers (XLI), the Citizens Utility Board of Minnesota (CUB) and Just Solar Coalition (JSC) were the only parties to quantify recommended financial adjustments. XLI recommended $112 million in proposed adjustments, based on reducing ROE, reducing recovery of incentive compensation and not including the prepaid pension asset in rate base. CUB recommended adjustments based on reducing ROE. Other parties provided specific issue recommendations.

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Proposed DOC modifications to NSP-Minnesota’s request:

(Millions of Dollars)	2022		2023		2024
NSP-Minnesota’s filed base revenue request	$	396	$	546	$	677
Recommended adjustments:
Rate base and rate of return (a)	(71)		(58)		(57)
MISO capacity credits	(55)		(94)		(94)
Monticello and wind farm life extension	(21)		(54)		(51)
PTC and ND ITC forecast	(28)		(40)		(43)
Property tax	(14)		(22)		(32)
Prepaid pension asset and liability	(13)		(21)		(32)
O&M expenses	(18)		(26)		(29)
Other, net	(48)		(57)		(65)
Total adjustments	(268)		(372)		(403)
Total proposed revenue change	$	128	$	174	$	274

(a)Included in the rate base and rate of return adjustments is an annual proposed increase in the cost of debt.

Positions on NSP-Minnesota’s filed rate request:

Recommended Position	DOC		XLI		CUB	JSC
ROE	9.25	%	9.17	%	8.80-9.00 %	9.06	%
Equity	52.5	%	N/A		N/A	N/A

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

•Rebuttal testimony: Nov. 8, 2022.

•Hearing: Dec. 13-16, 2022.

•ALJ Report: March 31, 2023.

•MPUC Order: June 30, 2023.

NSP-Minnesota — 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 return on equity (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 rate increase of $25 million, subject to refund, effective Jan. 1, 2022.

In October 2022, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following key terms:

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

•Revenue decoupling mechanism.

•Symmetrical property tax true-up.

•ROE of 9.57%.

•Equity ratio of 52.5%.

A hearing is scheduled for the fourth quarter of 2022 and a MPUC order is expected in the first half of 2023.

NSP-Minnesota — 2021 North Dakota Natural Gas Rate Case— In September 2021, NSP-Minnesota filed a request with the North Dakota Public Service Commission (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 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.

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

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

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NSP-Minnesota — 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. While the capital costs have increased, the passage of the IRA and other changes result in a levelized cost of energy that is approximately 30% lower than the original approval. In October 2022, NSP-Minnesota filed a request with the MPUC seeking approval of the higher capital costs for these repowering projects.

NSP-Minnesota — Sherco Solar Proposal — In September 2022, the MPUC approved NSP-Minnesota’s proposal to add 460 MW of solar facilities at the Sherco site. The project is expected to cost approximately $690 million (two phases to be completed in 2024 and 2025). As a result of the IRA, the levelized cost of the project is expected to be approximately 30% lower than previously estimated.

PSCo — Natural Gas Rate Case — In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the Pipeline System Integrity Adjustment (PSIA) rider. The request is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022. Additionally, PSCo’s request includes step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.

In October 2022, the CPUC issued a written decision approving a rate increase net of rider roll-ins of $64 million. The decision reflects a stated weighted average cost of capital (WACC) of 6.7%, a historic test year with a year-end rate base and $16 million of incremental depreciation expense. PSCo has the option to determine its ROE within a range of 9.2% to 9.5% and its equity ratio within a range of 52% to 55%, as long as it results in a WACC of 6.7%. PSCo anticipates using a ROE of 9.2% and an equity ratio of 53.8%. The CPUC denied the 2023-2024 step increases.

Note 5. Winter Storm Uri

In February 2021, the United States experienced Winter Storm Uri. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion. Xcel Energy has received recovery approval from all of our impacted states except for Texas, which is pending. A summary of pending and recently approved regulatory requests for cost recovery is listed below.

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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, pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period. In May 2022, the ALJs found the Winter Storm Uri fuel costs were prudently incurred and recommended no disallowances. In August 2022, the MPUC approved recovery of Uri storm costs with a $19 million disallowance.
PSCo	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 May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved a partial settlement providing full recovery of fuel costs with the exception of an $8 million disallowance.
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 approved. The interim rate recovery does not address the prudence of costs nor the retention of $11 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision. In July 2022, the intervenors filed recommendations in the Fuel Reconciliation proceeding. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins). A recommendation from the ALJ is expected in the fourth quarter of 2022 and a final decision is anticipated in the first quarter of 2023.

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Note 6. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2022 Earnings Guidance — Xcel Energy’s 2022 GAAP and ongoing earnings guidance is a narrowed range of $3.14 to $3.19 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%.

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

•Capital rider revenue is projected to be relatively flat (net of PTCs). The reduction in capital rider revenue is due to changes in expected PTC levels and is largely earnings neutral.

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

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

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

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

•AFUDC - equity is projected to be relatively flat.

•ETR is projected to be ~(7%) to (9%).

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

Key assumptions as compared with 2022 projected levels unless noted:

•Constructive outcomes in all rate case and regulatory proceedings.

•Normal weather patterns for the year.

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

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

•Capital rider revenue is projected to increase $70 million to $80 million (net of PTCs).

•O&M expenses are projected to be relatively flat.

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

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

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

•AFUDC - equity is projected to increase $0 million to $10 million.

•ETR is projected to be ~(5%) to (7%).

(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 2022 base of $3.15 per share, which represents the mid-point of the original 2022 guidance range of $3.10 to $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.

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XCEL ENERGY INC. AND SUBSIDIARIES

EARNINGS RELEASE SUMMARY (UNAUDITED)

(amounts in millions, except per share data)

	Three Months Ended Sept. 30
	2022		2021
Operating revenues:
Electric and natural gas	$	4,056	$	3,444
Other	26		23
Total operating revenues	4,082		3,467
Net income	$	649	$	609
Weighted average diluted common shares outstanding	548		539
Components of EPS — Diluted
Regulated utility	$	1.28	$	1.19
Xcel Energy Inc. and other costs	(0.09)		(0.06)
GAAP and ongoing diluted EPS (a)	$	1.18	$	1.13
Book value per share	$	29.90	$	28.12
Cash dividends declared per common share	0.4875		0.4575

	Nine Months Ended Sept. 30
	2022		2021
Operating revenues:
Electric and natural gas	$	11,178	$	10,007
Other	79		69
Total operating revenues	11,257		10,076
Net income	$	1,357	$	1,282
Weighted average diluted common shares outstanding	546		539
Components of EPS — Diluted
Regulated utility	$	2.69	$	2.54
Xcel Energy Inc. and other costs	(0.21)		(0.16)
GAAP and ongoing diluted EPS (a)	2.48		2.38
Book value per share	$	29.98	$	28.14
Cash dividends declared per common share	1.4625		1.3725

(a) For the three and nine months ended Sept. 30, 2022, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

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