Third quarter GAAP diluted earnings per share were $0.88 in 2025 compared with $1.21 in 2024.
Year-to-date GAAP diluted earnings per share were $2.47 in 2025 compared with $2.63 in 2024.
Third quarter ongoing diluted earnings per share were $1.24 in 2025 compared with $1.25 in 2024.
Year-to-date ongoing diluted earnings per share were $2.84 in 2025 compared with $2.69 in 2024.
Xcel Energy reaffirms its 2025 ongoing earnings per share guidance of $3.75 to $3.85.
Xcel Energy initiates its 2026 ongoing earnings per share guidance of $4.04 to $4.16.
Xcel Energy's long-term annual growth objectives reflect earnings per share growth of 6-8+% and dividend growth of 4-6%.

Xcel Energy Inc. (NASDAQ:XEL) today reported 2025 third quarter GAAP earnings of $524 million, or $0.88 per share, compared with $682 million, or $1.21 per share in the same period in 2024 and ongoing earnings of $737 million, or $1.24 per share compared with $707 million or $1.25 per share in the same period in 2024. See Note 6 for reconciliation from GAAP to ongoing earnings.

Third quarter ongoing earnings reflect higher depreciation, interest charges and O&M expenses partially offset by increased recovery of infrastructure investments.

"Today Xcel Energy unveiled our updated five-year infrastructure investment plan to serve increased energy demand from our communities, continue progress towards carbon reduction goals for our electric system and make needed investments to strengthen our transmission and distribution systems," said Bob Frenzel, chairman, president and CEO of Xcel Energy.

"We will continue to strive to ensure we keep customer bills as low as possible as we modernize and expand our country's energy infrastructure. By virtually all standards – share of wallet, national and state averages, or tracking at or below inflation rates - Xcel Energy customers have some of the country's lowest energy bills. "

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:	1 (866) 580-3963
International Dial-In:	(400) 120-0558
Conference ID:	2604371

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 October 30 to November 4.

Replay Numbers
US Dial-In:	1 (866) 583-1035
Access Code:	2604371#

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 2025 and 2026 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 or refunds to customers, expectations and intentions regarding regulatory proceedings, expected pension contributions, and expected impact on our results of operations, financial condition and cash flows of interest rate changes, increased credit exposure, and legal proceeding outcomes, 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, 2024 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: 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 workforce 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; uncertainty regarding epidemics; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy 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.

This information is not given in connection with any

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

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
		2025			2024			2025			2024
Operating revenues
Electric	$	3,638		$	3,393		$	9,351		$	8,737
Natural gas		264			239			1,715			1,535
Other		13			12			42			49
Total operating revenues		3,915			3,644			11,108			10,321

Operating expenses
Electric fuel and purchased power		1,098			1,060			3,036			2,863
Cost of natural gas sold and transported		61			63			708			664
Cost of sales — other		5			3			8			12
Operating and maintenance expenses		692			655			2,053			1,922
Conservation and demand side management expenses		101			112			299			295
Depreciation and amortization		750			681			2,200			2,042
Taxes (other than income taxes)		172			159			514			484
Marshall Wildfire litigation		287			—			287			—
Total operating expenses		3,166			2,733			9,105			8,282

Operating income		749			911			2,003			2,039

Other income, net		46			39			121			75
Earnings (loss) from equity method investments		6			3			(3	)		19
Allowance for funds used during construction — equity		79			44			196			119

Interest charges and financing costs
Interest charges — includes other financing costs		384			326			1,065			936
Allowance for funds used during construction — debt		(36	)		(21	)		(86	)		(51	)
Total interest charges and financing costs		348			305			979			885

Income before income taxes		532			692			1,338			1,367
Income tax expense (benefit)		8			10			(113	)		(105	)
Net income	$	524		$	682		$	1,451		$	1,472

Weighted average common shares outstanding:
Basic		592			564			584			559
Diluted		595			565			587			559

Earnings per average common share:
Basic	$	0.88		$	1.21		$	2.48		$	2.63
Diluted		0.88			1.21			2.47			2.63

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. For instance, to present ongoing earnings and ongoing diluted earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Note 1. Earnings Per Share Summary

Xcel Energy's third quarter GAAP diluted earnings were $0.88 per share compared with $1.21 per share in the same period in 2024 and ongoing earnings were $1.24 compared with $1.25 per share in 2024. The change in ongoing earnings per share was primarily driven by higher depreciation, interest charges and O&M expenses partially offset by increased recovery of infrastructure investments. 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		2025			2024			2025			2024
NSP-Minnesota	$	0.53		$	0.45		$	1.17		$	1.06
PSCo		0.08			0.45			0.79			1.06
SPS		0.27			0.31			0.55			0.58
NSP-Wisconsin		0.07			0.07			0.19			0.19
Earnings from equity method investments — WYCO		0.01			0.01			0.02			0.02
Regulated utility		0.96			1.29			2.72			2.91
Xcel Energy Inc. and Other		(0.07	)		(0.08	)		(0.24	)		(0.28	)
GAAP diluted EPS ^(a)	$	0.88		$	1.21		$	2.47		$	2.63
Sherco Unit 3 2011 outage refunds ^(b)		—			0.04			—			0.06
Marshall Wildfire settlement ^(b)		0.36			—			0.36			—
Ongoing diluted EPS ^(a)	$	1.24		$	1.25		$	2.84		$	2.69

^(a)		Amounts may not add due to rounding.
^(b)		See Note 6.

NSP-Minnesota — GAAP earnings increased $0.08 per share and ongoing earnings increased $0.04 for the third quarter. Year-to-date GAAP earnings increased $0.11 per share and ongoing earnings increased $0.05 per share. The year-to-date ongoing earnings increase was driven by higher recovery of electric infrastructure investments, which was partially offset by increased O&M expenses, depreciation and interest charges.

PSCo — GAAP earnings decreased $0.37 per share and ongoing earnings decreased $0.01 for the third quarter of 2025. Year-to-date GAAP earnings decreased $0.27 and ongoing earnings increased $0.09. The year-to-date ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and interest charges.

SPS — GAAP and ongoing earnings decreased $0.04 per share for the third quarter and decreased $0.03 year-to-date. The year-to-date change was driven by unfavorable weather, increased interest charges and O&M expenses, partially offset by higher recovery of electric infrastructure investments and sales growth.

NSP-Wisconsin — GAAP and ongoing earnings per share were flat for the third quarter of 2025 and year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, which was offset by increased depreciation and O&M expenses.

Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The change in earnings was largely due to gains on debt repurchases, partially offset by higher interest rates and debt levels and the performance of the equity method investments, which primarily invest in energy technology companies.

Components significantly contributing to changes in 2025 EPS compared to 2024:

Diluted Earnings (Loss) Per Share	Three Months Ended Sept. 30			Nine Months Ended Sept. 30
GAAP EPS — 2024	$	1.21		$	2.63

Components of change - 2025 vs. 2024
Higher electric revenues		0.28			0.76
Higher natural gas revenues		0.03			0.24
Higher AFUDC equity & debt		0.08			0.18
Sherco Unit 3 2011 outage refunds (See Note 6)		0.04			0.06
Marshall Wildfire settlement (See Note 6)		(0.36	)		(0.36	)
Higher electric fuel and purchased power ^(a)		(0.05	)		(0.23	)
Higher depreciation		(0.09	)		(0.21	)
Higher O&M expenses		(0.05	)		(0.17	)
Higher interest charges		(0.08	)		(0.17	)
Higher costs of natural gas sold and transported ^(a)		—			(0.06	)
Common stock equity dilution		(0.07	)		(0.14	)
Other, net		(0.06	)		(0.06	)
GAAP EPS — 2025	$	0.88		$	2.47
Marshall Wildfire settlement (See Note 6)		0.36			0.36
Ongoing EPS — 2025 ^(b)	$	1.24		$	2.84

^(a)		Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.
^(b)		Amounts may not add due to rounding.

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. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.

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
	2025 vs. Normal		2024 vs. Normal			2025 vs. 2024			2025 vs. Normal			2024 vs. Normal			2025 vs. 2024
Retail electric	$	0.006	$	0.038		$	(0.032	)	$	(0.001	)	$	0.015		$	(0.016	)
Sales true-up ^(a)		—		(0.001	)		0.001			—			0.040			(0.040	)
Electric total	$	0.006	$	0.037		$	(0.031	)	$	(0.001	)	$	0.055		$	(0.056	)
Firm natural gas		—		(0.002	)		0.002			—			(0.040	)		0.040
Decoupling		0.001		(0.001	)		0.002			0.003			0.017			(0.014	)
Natural gas total	$	0.001	$	(0.003	)	$	0.004		$	0.003		$	(0.023	)	$	0.026
Total	$	0.007	$	0.034		$	(0.027	)	$	0.002		$	0.032		$	(0.030	)

(a)

The sales true-up mechanism in NSP-Minnesota expired in 2024 and is proposed in the pending Minnesota electric rate case to be reestablished in 2026.

Sales — Sales growth (decline) for actual and weather-normalized sales in 2025 compared to 2024:

	Three Months Ended Sept. 30
	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	6.4	%	(0.1	)%	(7.5	)%	3.5	%	1.6	%
Electric C&I	(0.8	)	(1.5	)	5.4		0.1		1.0
Total retail electric sales	1.7		(0.9	)	2.8		1.0		1.1
Firm natural gas sales	3.7		4.9		N/A		(4.5	)	4.0

	Three Months Ended Sept. 30
	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	1.9	%	5.2	%	3.3	%	1.9	%	3.3	%
Electric C&I	(1.9	)	1.5		6.5		(0.1	)	1.9
Total retail electric sales	(0.6	)	2.9		5.7		0.4		2.2
Firm natural gas sales	1.7		1.7		N/A		(6.2	)	1.2

	Nine Months Ended Sept. 30
	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Xcel Energy
Actual
Electric residential	6.0	%	(0.9	)%	(2.1	)%	6.1	%	2.2	%
Electric C&I	0.1		(0.3	)	6.3		0.2		1.9
Total retail electric sales	2.0		(0.5	)	4.7		1.8		1.9
Firm natural gas sales	15.0		2.2		N/A		18.5		7.0

	Nine Months Ended Sept. 30
	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	1.2	%	2.4	%	4.4	%	1.7	%	2.2	%
Electric C&I	(0.9	)	1.2		7.0		(0.2	)	2.2
Total retail electric sales	(0.2	)	1.6		6.4		0.3		2.1
Firm natural gas sales	—		(2.0	)	N/A		2.4		(1.1	)

	Nine Months Ended Sept. 30 (Leap Year Adjusted)
	NSP-Minnesota		PSCo		SPS		NSP-Wisconsin		Xcel Energy
Weather-Normalized
Electric residential	1.6	%	2.8	%	4.8	%	2.1	%	2.5	%
Electric C&I	(0.5	)	1.6		7.4		0.1		2.6
Total retail electric sales	0.2		2.0		6.8		0.6		2.5
Firm natural gas sales	0.9		(1.2	)	N/A		3.3		(0.3	)

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

NSP-Minnesota — Residential sales increased due to customer growth (1.1%) and increase in use per customer (0.4%). C&I sales decreased due to lower use per customer.
PSCo — Residential sales increased due to increased use per customer (1.6%) and customer growth (1.2%). C&I sales increased due to higher use per customer and customer growth, primarily in the information and energy sectors.
SPS — Residential sales increased due to higher use per customer (4.1%) and customer growth (0.7%). C&I sales increased due to higher use per customer, primarily driven by the energy sector.
NSP-Wisconsin — Residential sales increased due to both increased use per customer (1.1%) and customer growth (1.0%).

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

Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential, partially offset by growth in other jurisdictions.

Electric Revenues — Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.

(Millions of Dollars)	Three Months Ended Sept. 30, 2025 vs. 2024			Nine Months Ended Sept. 30, 2025 vs. 2024
Recovery of higher cost of electric fuel and purchased power	$	28		$	160
Non-fuel riders		35			151
Regulatory rate outcomes (MN and ND)		46			98
Sales and demand		44			98
Transmission revenues		14			48
Sherco Unit 3 2011 outage refunds (see Note 6)		35			46
PTCs flowed back to customers (offset in ETR)		32			17
Estimated impact of weather		(21	)		(39	)
Conservation and demand side management (offset in expense)		(19	)		(34	)
Other, net		51			69
Total increase	$	245		$	614

Natural Gas Revenues — Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.

(Millions of Dollars)	Three Months Ended Sept. 30, 2025 vs. 2024			Nine Months Ended Sept. 30, 2025 vs. 2024
Regulatory rate outcomes (CO)	$	10		$	82
Recovery of higher cost of natural gas		5			53
Conservation revenue (offset in expense)		6			34
Estimated impact of weather (net of decoupling)		3			19
Retail sales decline (net of decoupling)		(3	)		(13	)
Other, net		4			5
Total increase	$	25		$	180

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Electric fuel and purchased power expenses increased $38 million for the third quarter of 2025 and $173 million year-to-date. The year-to-date increase was primarily due to increased commodity prices and transmission expense partially offset by decreased volumes and timing of fuel recovery mechanisms.

Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.

Natural gas sold and transported decreased $2 million for the third quarter of 2025 and increased $44 million year-to-date. The year-to-date increase was primarily due to higher commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.

O&M Expenses — O&M expenses increased $37 million for the third quarter of 2025 and $131 million year-to-date. The year-to-date increase was primarily due to increased benefits and healthcare costs, nuclear generation costs and insurance costs.

Depreciation and Amortization — Depreciation and amortization increased $69 million for the third quarter of 2025 and $158 million year-to-date. The year-to-date increase was largely the result of system investment.

Other Income — Other income increased $7 million for the third quarter of 2025 and $46 million year-to-date, largely due to gains on debt repurchases in the second quarter of 2025.

Interest Charges — Interest charges increased $58 million for the third quarter of 2025 and $129 million year-to-date, largely due to higher debt levels and interest rates.

AFUDC, Equity and Debt — AFUDC increased $50 million for the third quarter of 2025 and $112 million year-to-date, largely the result of system investment.

Income Taxes — Effective income tax rate:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2025		2024		2025 vs. 2024		2025		2024		2025 vs. 2024
Federal statutory rate	21.0	%	21.0	%	—	%	21.0	%	21.0	%	—	%
State income tax on pretax income, net of federal tax effect	5.2		4.7		0.5		4.9		4.8		0.1
(Decreases) increases in tax from:
PTCs ^(a)	(17.0	)	(16.0	)	(1.0	)	(27.0	)	(26.2	)	(0.8	)
Plant regulatory differences ^(b)	(8.2	)	(5.7	)	(2.5	)	(7.2	)	(5.9	)	(1.3	)
Other tax credits, net NOL & tax credit allowances	(0.4	)	(1.5	)	1.1		(0.9	)	(1.1	)	0.2
Other, net	0.9		(1.1	)	2.0		0.8		(0.3	)	1.1
Effective income tax rate	1.5	%	1.4	%	0.1	%	(8.4	)%	(7.7	)%	(0.7	)%

(a)		Wind and solar PTCs (net of estimated transfer discounts) are generally 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. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

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

Xcel Energy's capital structure:

(Millions of Dollars)	Sept. 30, 2025		Percentage of Total Capitalization		Dec. 31, 2024		Percentage of Total Capitalization
Current portion of long-term debt	$	1	—	%	$	1,103	2	%
Short-term debt		1,330	2			695	2
Long-term debt		32,034	59			27,316	56
Total debt		33,365	61			29,114	60
Common equity		21,181	39			19,522	40
Total capitalization	$	54,546	100	%	$	48,636	100	%

Liquidity — As of Oct. 27, 2025, 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.	$	2,000	$	620	$	1,380	$	16	$	1,396
PSCo		1,200		48		1,152		65		1,217
NSP-Minnesota		800		44		756		13		769
SPS		600		—		600		2		602
NSP-Wisconsin		150		—		150		113		263
Total	$	4,750	$	712	$	4,038	$	209	$	4,247

^(a)		Expires December 2029.
^(b)		Includes outstanding commercial paper and letters of credit.

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 and long-term outlook assigned to Xcel Energy Inc. and its utility subsidiaries as of Oct. 27, 2025:

Moody's

S&P Global Ratings

Fitch

Company

Credit Type

Rating

Outlook

Rating

Outlook

Rating

Outlook

Xcel Energy Inc.

Unsecured

Baa1

Stable

BBB

Stable

BBB+

Stable

NSP-Minnesota

Secured

Aa3

Stable

A+

Stable

NSP-Wisconsin

Secured

Stable

A+

Stable

PSCo

Secured

Stable

Negative

A+

Stable

SPS

Secured

Stable

A-

Stable

A-

Stable

Xcel Energy Inc.

Commercial paper

P-2

A-2

NSP-Minnesota

Commercial paper

P-1

A-2

NSP-Wisconsin

Commercial paper

P-2

A-2

PSCo

Commercial paper

P-2

A-2

SPS

Commercial paper

P-2

A-2

Capital Expenditures — Base capital expenditures for Xcel Energy for 2026 through 2030:

	Base Capital Forecast (Millions of Dollars)
By Regulated Utility		2026		2027			2028			2029			2030		Total
NSP-Minnesota	$	3,740	$	4,870		$	4,210		$	3,660		$	3,650		$	20,130
SPS		3,050		5,120			5,350			3,240			2,270			19,030
PSCo		5,980		3,940			2,960			1,760			2,960			17,600
NSP-Wisconsin		910		1,210			760			570			580			4,030
Other ^(a)		110		(10	)		(630	)		(210	)		(50	)		(790	)
Total base capital expenditures	$	13,790	$	15,130		$	12,650		$	9,020		$	9,410		$	60,000

(a)

Other category includes intercompany transfers for equipment with long lead times.

	Base Capital Forecast (Millions of Dollars)
By Function		2026		2027		2028		2029		2030	Total
Electric transmission	$	3,060	$	2,930	$	2,890	$	3,190	$	3,370	$	15,440
Renewables		3,560		4,620		3,380		1,150		1,210		13,920
Electric distribution		2,920		3,250		2,930		1,680		2,930		13,710
Electric generation		2,220		2,420		2,500		1,810		590		9,540
Natural gas		860		830		700		650		680		3,720
Other		1,170		1,080		250		540		630		3,670
Total base capital expenditures	$	13,790	$	15,130	$	12,650	$	9,020	$	9,410	$	60,000

The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt.

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, 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.

Financing for Capital Expenditures through 2030 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2026-2030 (includes the impact of tax credit transferability):

(Millions of Dollars)
Funding Capital Expenditures
Cash from operations ^(a)	$	30,180
New debt ^(b)		22,820
Equity issuances ^(c)		7,000
Base capital expenditures 2026-2030	$	60,000

Maturing debt	$	3,580

^(a)		Net of dividends and pension funding.
^(b)		Reflects a combination of short and long-term debt; net of refinancing.
^(c)		Amount could include other financing instruments that receive equity credit from the credit rating agencies.

2025 Financing Activity — During 2025, Xcel Energy Inc. and its utility subsidiaries issued the following long-term debt. No further debt issuances are planned for 2025.

Issuer	Security	Amount (in millions)	Tenor	Coupon
Xcel Energy Inc.	Senior Unsecured Notes	$ 1,100	3 Year & 10 Year	4.75% & 5.60%
PSCo	First Mortgage Bonds	1,000	9 Year & 30 Year	5.35% & 5.85%
SPS	First Mortgage Bonds	500	10 Year	5.30%
NSP-Minnesota	First Mortgage Bonds	1,100	10 Year & 30 Year	5.05% & 5.65%
NSP-Wisconsin	First Mortgage Bonds	250	29 Year	5.65%
PSCo	First Mortgage Bonds	1,000	10 Year & 30 Year	5.15% & 5.85%
Xcel Energy Inc. ^(a)	Junior Subordinated Debt	900	60 Year	6.25%

^(a)

Junior subordinated debt was issued on Oct. 7, 2025.

Xcel Energy issued 16.4 million shares ($1.16 billion in net proceeds) through its at-the-market programs in the nine months ended Sept. 30, 2025. Xcel Energy also entered forward equity agreements and collared forward equity agreements under these programs totaling 18.2 million shares (minimum expected proceeds of $1.3 billion), which have not been settled.

Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.

Note 4. Rates, Regulation and Other

NSP-Minnesota — 2024 Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million.

In August 2025, eight 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), Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. XLI recommended $190 million in proposed adjustments, based on a reduced ROE and a reduction in certain O&M expenses. CUB recommended proposed adjustments based on a reduced ROE and elimination of reconnection and late fee revenues. Walmart recommended an adjustment based on a reduced ROE. Other parties provided issue specific recommendations.

Proposed DOC modifications to NSP-Minnesota's request are summarized below:

(Millions of Dollars)		2025			2026
NSP-Minnesota's filed base revenue request	$	344		$	473

Recommended adjustments:
Rate of return		(101	)		(107	)
O&M expenses		(62	)		(56	)
Generation capacity revenue ^(a)		(39	)		(40	)
Depreciation		(29	)		(32	)
Federal production tax credits ^(a)		(22	)		(10	)
Riverside Generating Plant outage ^(b)		(18	)		(13	)
Prepaid pension assets and liability		(11	)		(11	)
Property tax ^(a)		(4	)		(12	)
Other, net		(9	)		(25	)
Total adjustments		(295	)		(306	)

Total proposed revenue change	$	49		$	167

^(a)		Adjustments largely offset in trackers.
^(b)		Riverside Generating Plant experienced a mechanical failure in April 2025 that resulted in an extended outage.

Positions on NSP-Minnesota's filed rate request:

Recommended Position	DOC	XLI	CUB	Walmart
ROE	9.25 %	8.96 %	9.00 %	9.25 %
Equity	52.50 %	N/A	N/A	N/A

In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers.

An Administrative Law Judge (ALJ) report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.

NSP-Minnesota — 2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the South Dakota Public Utilities Commission (SDPUC) for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. NSP-Minnesota will request interim rates to begin on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.

The procedural schedule is as follows:

Intervenor direct testimony: March 20, 2026
Rebuttal testimony: April 14, 2026
Evidentiary Hearing: April 28-30, 2026

A SDPUC decision is expected in the second quarter of 2026.

NSP-Minnesota — 2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).

On July 8, 2025, two intervenors filed testimony with a range of recommendations. NDPSC Staff recommended an increase of approximately $30 million, with a 9.41% ROE and a 50% equity ratio, along with other proposed adjustments that were not quantified. NSP-Minnesota estimates the NDPSC Staff recommendation would result in a rate increase of $20 million to $25 million. A NDPSC decision is expected in early 2026.

NSP-Minnesota — Prairie Island Outage Prudency Review — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC. In a response to that petition, intervenors recommended refunds for replacement power costs related to an outage at the Prairie Island generating station (October 2023 through February 2024).

In a September 2024 decision, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota recorded an estimated liability for a customer refund in 2024.

In May 2025, in the resulting case currently before an ALJ to determine the refund amount, NSP-Minnesota submitted direct testimony asserting that no more than $6 million of customer refunds are warranted for the outage.

In July 2025, intervenor direct testimony was filed by the DOC, OAG, and XLI. These parties, together with the CUB, also filed a joint motion requesting the ALJ rule that customer refunds cannot be adjusted as proposed by NSP-Minnesota, including certain reductions for avoided future outages. If NSP-Minnesota's proposed adjustments were rejected, and other DOC and OAG direct testimony recommendations were applied to both 2023 and 2024, NSP-Minnesota estimates that the customer refunds would be approximately $34 million. The joint motion was denied in August 2025, and the application of the adjustments will be addressed in the case before the ALJ.

Rebuttal and surrebuttal testimony were filed in August and September 2025. An ALJ report is expected in March 2026, with a MPUC decision expected in the second quarter of 2026.

NSP-Minnesota — 2025 Natural Gas Rate Case — On Oct. 31, 2025, NSP-Minnesota plans to file a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota will also request interim rates of $51 million to go into effect on Jan. 1, 2026. As part of the request, NSP-Minnesota plans to file an option for a stay-out alternative.

NSP-Wisconsin — Wisconsin Electric and Natural Gas Rate Case – In March 2025, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) for a multi-year electric and natural gas rate increase.

For the electric utility, NSP-Wisconsin is seeking a total electric revenue increase of $94 million (11.8%) in 2026 and an incremental $57 million (7.1%) in 2027, for a total of $151 million over the two-year period of 2026 and 2027. The electric rate increase is based on electric rate base of $2.9 billion in 2026 and $3.2 billion in 2027. For the natural gas utility, NSP-Wisconsin requested a total natural gas revenue increase of $20 million (12.7%) in 2026 and an incremental $4 million (1.5%) in 2027, for a total of $24 million (14.2%) over the two-year period of 2026 and 2027. The natural gas rate increase is based on natural gas rate base of $0.3 billion in 2026 and $0.4 billion in 2027. Both the electric and natural gas rate requests are based on forward-looking test years, with a 10.0% ROE and an equity ratio of 53.5%.

On August 8, 2025, the PSCW Staff and intervenors filed their direct testimony. The PSCW Staff recommended an electric base rate increase of $115 million or 14.4% over the two-year period. The PSCW Staff additionally recommended a natural gas rate increase of $21 million, or 12.3% over the two-year period, all based on a ROE of 9.7% and an equity ratio of 53.5%.

Intervenors mainly limited their comments on revenue requirements to ROE focusing the majority of their testimony on cost of service, rate design and other policy issues. The major components of the PSCW Staff recommendation are summarized below:

(Millions of Dollars)	Electric			Natural Gas
NSP-Wisconsin's filed two-year rate request	$	151		$	24

PSCW Staff recommended adjustments:
Capital investments ^(a)		(15	)		(1	)
ROE adjustment		(7	)		(1	)
O&M expenses		(6	)		(1	)
Nuclear decommissioning accrual update ^(b)		(6	)		—
Other, net		(2	)		—
Proposed revenue change	$	115		$	21

^(a)		Capital investment adjustment includes $7 million associated with two MISO Long Range Transmission Plan (LRTP) projects that are pending PSCW approval (Grid Forward and Western Wisconsin Transmission Connection). It is PSCW Staff historic practice to recommend adjustments for projects until Commission approval is received. Approval of both LRTP projects is anticipated in the fourth quarter of 2025.
^(b)		Since filing the case, the Minnesota Public Utilities Commission authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral.

A PSCW decision is anticipated in the fourth quarter of 2025.

PSCo — 2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.

The plan reflects a base sales forecast with 7% compound annual sales growth through 2031.
The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.
The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios. The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio. The table below summarizes two of the proposed portfolios based on the different sales scenarios:

(Megawatts)	Base Plan	Low Load
Wind	7,250	2,800
Solar	3,077	1,200
Natural gas combustion turbine	1,575	1,400
Storage (long duration)	1,600	—
Other storage	450	—
Total	13,952	5,400

A hearing was held in June 2025 and a CPUC decision on the resource need is expected in the fourth quarter of 2025 with the competitive solicitation for resource additions expected in early 2026.

PSCo — Near-Term Procurement — In August 2025, PSCo filed a joint motion with state agencies to initiate a "fast-tracked" solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 MW of clean energy resources, 200 MW of firm, dispatchable resources, and up to 300 MW of other dispatchable resources. A recommended portfolio of resources will be filed December 2025 and a decision is expected in February 2026.

PSCo — Wildfire Mitigation Plan — In June 2024, PSCo filed an Updated Wildfire Mitigation Plan (the WMP) and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion.

The WMP integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner.

In April 2025, PSCo filed with the CPUC a comprehensive and unanimous settlement. Key terms include:

Approval of the updated WMP, including scope of mitigation activities and the Public Safety Power Shutoffs plan, with certain modifications.
Cost recovery of proposed investments through a Wildfire Mitigation Adjustment rider and recovery of transmission investments through the Transmission Cost Adjustment rider.
PSCo agrees to request approval to pursue securitization of an estimated $1.2 billion of proposed WMP investments, with a target to complete the transaction by Jan. 1, 2029.
Extension of the excess liability insurance deferral, with a cap of $50 million after PSCo's current policy year, which ends October 2025.

In August 2025, the CPUC issued a written approval of the settlement agreement.

SPS — SPS Resource Plan (IRP) — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS' projected resource needs range from approximately 5,300 MW to 10,200 MW of nameplate capacity by 2030. In February 2024, the NMPRC accepted the IRP.

In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited capacity by 2030. The total capacity to be added to the system is expected to align with the range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.

In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:

Generation Resource Nameplate Capacity (in Megawatts)	Company Owned	Power Purchase Agreements	Total
Wind Resources	1,273	—	1,273
Solar	695	—	695
Storage	472	640	1,112
Natural Gas	2,088	—	2,088
Total	4,528	640	5,168

SPS filed or expects to file Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025, with approvals expected in 2026.

In October 2025, SPS issued a second RFP to solicit 870 MW of accredited capacity (approximately 1,500 MW to 3,000 MW nameplate capacity) through 2032. Additional resources will be evaluated to meet the New Mexico Renewable Portfolio Standard compliance need. Bids are due in January 2026, and the portfolio is expected to be filed in the second half of 2026.

SPS — Excess Liability Insurance Deferral — In March 2025, SPS filed a request with the PUCT and in April 2025, SPS filed a request with the NMPRC for deferred accounting treatment for incremental excess liability insurance expense incurred as a result of the October 2024 policy renewal, estimated at approximately $30 million across the two jurisdictions. In October 2025, the NMPRC approved the request, resulting in a deferral of approximately $15 million of incremental excess liability insurance costs in 2025. A PUCT decision is expected in the first quarter of 2026.

Note 5. Wildfire Litigation

Marshall Wildfire Litigation —In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

On June 8, 2023, the Boulder County Sheriff's Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff's Report). According to the Sheriff's Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo's service territory, for reasons unrelated to PSCo's power lines. According to the Sheriff's Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo's service territory. According to the Sheriff's Report, the second ignition started approximately 80 to 110 feet away from PSCo's power lines in the area.

PSCo is aware of 307 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,087 plaintiffs. The complaints generally allege that PSCo's equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. Certain of the complaints also seek exemplary damages. In addition to asserting claims against PSCo, Xcel Energy Inc. and Xcel Energy Services, various Plaintiffs, including insurance company plaintiffs, asserted claims against certain telecommunications companies (the Telecom Companies). In April 2025, most of the remaining plaintiffs amended their complaints to also assert claims against the Telecom Companies. In June 2025, the Boulder County District Court dismissed Xcel Energy Inc. from the complaints that named that entity as a defendant, due to lack of jurisdiction.

An initial trial on liability issues was scheduled to start in September 2025. Prior to trial, in September 2025, Xcel Energy, Qwest Corporation and Teleport Communications America, LLC reached settlement agreements in principle that resolve all claims asserted by the subrogation insurers, the public entity plaintiffs and individual plaintiffs. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.

PSCo expects to pay approximately $640 million related to these settlements, with approximately $353 million expected to be reimbursed to PSCo by remaining insurance coverage (after consideration of legal costs incurred to date). PSCo recognized a $287 million charge to earnings as a result of these settlement agreements in the quarterly period ended September 30, 2025.

A remaining estimated liability of $640 million is presented in other current liabilities as of Sept. 30, 2025; no estimated liability was recognized as of Dec. 31, 2024. PSCo records insurance recoveries when it is deemed probable that recovery will occur, and PSCo can reasonably estimate the amount or range. Insurance receivables of $353 million related to the settlement are presented in prepayments and other current assets as of Sept. 30, 2025; no such insurance receivables were recognized as of Dec. 31, 2024.

The agreements in principle remain subject to final documentation and individual plaintiffs opting in to the agreements negotiated and recommended by their counsel. The trial that was scheduled to begin in September 2025 has been vacated to allow the parties time to execute definitive settlement agreements. To the extent any individual plaintiffs choose to opt out of the agreements negotiated and recommended by their counsel and such cases are not otherwise resolved, they will be subject to further litigation.

2024 Smokehouse Creek Fire Complex — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the "Smokehouse Creek Fire Complex"). The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed. According to the Texas A&M Forest Service's Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres. In August 2025, the Texas Attorney General's office announced that it was opening a civil investigation into utilities, including Xcel Energy and SPS, connected to the Smokehouse Creek and Windy Deuce fires. The company is cooperating with that investigation.

SPS is aware of approximately 34 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints, which assert claims on behalf of one or more plaintiffs, generally allege that SPS' equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. Of the 34 complaints, 12 have been resolved and dismissed to date, with nine others settled or settled in principle, and pending dismissal.

SPS has received 254 claims through its claims process and has reached final settlements on 212 of those claims as of the date of this filing. In addition to filed complaints and claims made through SPS' claims process, SPS has also received information from attorneys for approximately 83 claims which have not been submitted through the claims process and have also not been filed as lawsuits, and has reached settlement of 71 of those claims through mediation.

SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex. Settlements have also been reached with the subrogated insurer plaintiffs as well as the three largest claims that have been asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $361 million of expected loss payments, of which $219 million and $35 million were paid through Sept. 30, 2025 and Dec. 31, 2024, respectively.

Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy has recorded $410 million of total estimated losses for the matter (before available insurance). This represents a $120 million increase from the estimated losses as of June 30, 2025, largely driven by actual settlement activity for large claims and previously inestimable categories, such as damage to trees. A remaining estimated liability of $191 million and $180 million is presented in other current liabilities as of Sept. 30, 2025 and Dec. 31, 2024, respectively.

The cumulative estimated probable losses of $410 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the total of actual settlements reached to date plus the low end of the range for remaining reasonably estimable losses, and is subject to change as additional information becomes available. This $410 million estimate does not include amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) unsettled compensation claims for damage to trees and oil and gas equipment, or (v) other amounts that are not reasonably estimable.

Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including whether additional complaints and demands may be made. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.

The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.

Texas law does not apply strict liability in determining an electric utility company's liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.

Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.

SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. Insurance receivables of $341 million and $210 million, net of recoveries received are presented in prepayments and other current assets as of Sept. 30, 2025 and Dec. 31, 2024, respectively. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

Note 6. Non-GAAP Reconciliation

Xcel Energy's reported earnings are prepared in accordance with GAAP. Xcel Energy's management believes that ongoing earnings, or GAAP earnings adjusted for certain items, reflect management's performance in operating the company and provides a meaningful representation of the underlying performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Earnings Adjusted for Certain Items (Ongoing Earnings)

The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Millions of Dollars)		2025			2024			2025			2024
GAAP net income	$	524		$	682		$	1,451		$	1,472
Sherco Unit 3 2011 outage refunds		—			35			—			46
Marshall Wildfire litigation		287			—			287			—
Tax effect		(74	)		(10	)		(74	)		(13	)
Ongoing earnings	$	737		$	707		$	1,664		$	1,505

Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota's Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues.

Marshall Wildfire Litigation — In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation. See Note 5.

Note 7. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2025 Earnings Guidance — Xcel Energy's 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.^(a)

Key assumptions as compared with 2024 actual levels unless noted:

Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.
Normal weather patterns for the year.
Weather-normalized retail electric sales are projected to increase ~3%.
Weather-normalized retail firm natural gas sales are projected to be flat.
Capital rider revenue is projected to increase $255 million to $265 million (net of PTCs).
O&M expenses are projected to increase ~5%. The increase from prior guidance is primarily due to increasing benefit costs in the third quarter of 2025.
Depreciation expense is projected to increase approximately $220 million to $230 million. The increase from prior guidance is largely earnings neutral and is offset by changes in electric fuel and purchased power.
Property taxes are projected to increase $45 million to $55 million.
Interest expense (net of AFUDC - debt) is projected to increase $180 million to $190 million, net of interest income. The increase from prior guidance is largely earnings neutral and is offset by changes in electric fuel and purchased power.
AFUDC - equity is projected to increase $110 million to $120 million.

Xcel Energy 2026 Earnings Guidance — Xcel Energy's 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. ^(a)

Key assumptions as compared with 2025 actual levels unless noted:

Constructive outcomes in all pending rate case and regulatory proceedings.
Normal weather patterns for the year.
Weather-normalized retail electric sales are projected to increase ~3%.
Weather-normalized retail firm natural gas sales are projected to increase ~1%.
Capital rider revenue is projected to increase $550 million to $560 million.
O&M expenses are projected to increase ~3%.
Depreciation expense is projected to increase approximately $370 million to $380 million.
Property taxes are projected to increase $30 million to $40 million.
Interest expense (net of AFUDC - debt) is projected to increase $290 million to $300 million, net of interest income.
AFUDC - equity is projected to increase $140 million to $150 million.

^(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. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to 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 6% to 8+% based off of $3.80 per share (the mid-point of 2025 original ongoing earnings guidance of $3.75 to $3.85 per share).
Deliver annual dividend increases of 4% to 6%.
Target a dividend payout ratio of 45% to 55%.
Maintain senior secured debt credit ratings in the A range.

XCEL ENERGY INC. AND SUBSIDIARIES EARNINGS RELEASE SUMMARY (UNAUDITED) (amounts in millions, except per share data)

	Three Months Ended Sept. 30
		2025			2024
Operating revenues:
Electric and natural gas	$	3,902		$	3,632
Other		13			12
Total operating revenues		3,915			3,644

Net income	$	524		$	682

Weighted average diluted common shares outstanding		595			565

Components of EPS — Diluted
Regulated utility	$	0.96		$	1.29
Xcel Energy Inc. and other costs		(0.07	)		(0.08	)
GAAP diluted EPS ^(a)	$	0.88		$	1.21
Sherco Unit 3 2011 outage refunds (See Note 6)		—			0.04
Marshall Wildfire litigation (See Note 6)		0.36			—
Ongoing diluted EPS ^(a)	$	1.24		$	1.25

Book value per share	$	35.59		$	34.28
Cash dividends declared per common share		0.57			0.5475

^(a)

Amounts may not add due to rounding.

	Nine Months Ended Sept. 30
		2025			2024
Operating revenues:
Electric and natural gas	$	11,066		$	10,272
Other		42			49
Total operating revenues		11,108			10,321

Net income	$	1,451		$	1,472

Weighted average diluted common shares outstanding		587			559

Components of EPS — Diluted
Regulated utility	$	2.72		$	2.91
Xcel Energy Inc. and other costs		(0.24	)		(0.28	)
GAAP diluted EPS ^(a)	$	2.47		$	2.63
Sherco Unit 3 2011 outage refunds (See Note 6)		—			0.06
Marshall Wildfire litigation (See Note 6)		0.36			—
Ongoing diluted EPS ^(a)	$	2.84		$	2.69

Book value per share	$	36.11		$	34.61
Cash dividends declared per common share		1.71			1.6425

^(a)

Amounts may not add due to rounding.

View source version on businesswire.com: https://www.businesswire.com/news/home/20251030667602/en/

For more information, contact:

Roopesh Aggarwal, Vice President - Investor Relations, (612) 215-4535

Xcel Energy website address: www.xcelenergy.com

Xcel Energy Third Quarter 2025 Earnings Report