• Second quarter diluted GAAP and ongoing earnings per share were $0.75 in 2025 compared with $0.54 in 2024.
• Year-to-date diluted GAAP and ongoing earnings per share were $1.59 in 2025 compared with $1.42 in 2024.
• Xcel Energy reaffirms its 2025 ongoing earnings per share guidance of $3.75 to $3.85.

Xcel Energy Inc. (NASDAQ: XEL) today reported 2025 second quarter GAAP earnings of $444 million, or $0.75 per share, compared with $302 million, or $0.54 per share in the same period in 2024.

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

“Xcel Energy continues to deliver on our commitments to our customers, communities and investors.” said Bob Frenzel, chairman, president and CEO of Xcel Energy. “During the second quarter, we made considerable progress on investments needed to serve unprecedented growth in electric demand and to improve resiliency and reliability of our systems. In Texas and New Mexico, we filed our recommended portfolio for nearly 5,200 MW of new generation, of which 4,500 MW will be company owned. We also continue to make progress reducing risk from wildfires and extreme weather on our system, with both the Colorado and Texas commissions approving our settlements for our Wildfire Mitigation and System Resiliency Plans.”

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.

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 July 31 to August 5.

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 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

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. For the three and six months ended June 30, 2025 and 2024, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Note 1. Earnings Per Share Summary

Xcel Energy’s second quarter GAAP and ongoing diluted earnings were $0.75 per share compared with $0.54 per share in the same period in 2024. The change in earnings per share was primarily driven by increased recovery of infrastructure investments partially offset by higher O&M expenses, depreciation and interest charges. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).

Summarized diluted EPS for Xcel Energy:

PSCo — GAAP and ongoing earnings increased $0.05 per share for the second quarter of 2025 and $0.10 year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and interest charges.

NSP-Minnesota — GAAP and ongoing earnings increased $0.08 per share for the second quarter of 2025 and $0.03 year-to-date. The year-to-date change was driven by higher recovery of electric infrastructure investments, which was partially offset by increased O&M expenses, depreciation and interest charges.

SPS — GAAP and ongoing earnings increased $0.01 per share for the second quarter of 2025 and year-to-date. The year-to-date change was driven by higher recovery of electric infrastructure investments and sales growth, partially offset by increased interest and O&M expenses.

NSP-Wisconsin — GAAP and ongoing earnings increased $0.01 per share for the second quarter of 2025 and were flat 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 O&M expenses and depreciation.

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 increase in earnings was largely due to a gain on debt repurchases, partially offset by the performance of the equity method investments, which primarily invest in energy technology companies, and higher debt levels.

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

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:

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

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

• PSCo — Residential sales increased largely due to customer growth (1.3%). C&I sales increased due to higher use per customer and customer growth, primarily in the information and energy sectors.
• NSP-Minnesota — Residential sales increased due to customer growth (1.2%) and increase in use per customer (0.2%). C&I sales increased due to customer growth, largely in the manufacturing sector.
• SPS — Residential sales increased due to higher use per customer (5.0%) and customer growth (0.7%). C&I sales increased due to higher use per customer and customer growth, 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.

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

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 $63 million for the second quarter of 2025 and $135 million year-to-date. The year-to-date increase was primarily due to increased commodity prices partially offset by 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 increased $16 million for the second quarter of 2025 and $46 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 $13 million for the second quarter of 2025 and $94 million year-to-date. The year-to-date increase was primarily due to increased insurance and benefit costs, higher nuclear generation costs and the impact of a 2024 gain on land sale.

Depreciation and Amortization — Depreciation and amortization increased $19 million for the second quarter of 2025 and $89 million year-to-date. The year-to-date increase was largely the result of system investment.

Other Income — Other income increased $46 million for the second quarter of 2025 and $39 million year-to-date, largely due to a gain on debt repurchases.

Interest Charges — Interest charges increased $30 million for the second quarter of 2025 and $71 million year-to-date, largely due to higher debt levels and interest rates.

AFUDC, Equity and Debt — AFUDC increased $42 million for the second quarter of 2025 and $62 million year-to-date, largely the result of system investment.

Income Taxes — Effective income tax rate:

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

Xcel Energy’s capital structure:

Liquidity — As of July 28, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

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 July 28, 2025:

2025 Financing Activity — During 2025, Xcel Energy Inc. and its utility subsidiaries have completed or plan to complete the following long-term debt issuances:

Xcel Energy issued approximately $1.15 billion of equity through its at-the-market program in the six months ended June 30, 2025. In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $4.75 billion.

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, seeking a total revenue increase of $491 million (13.2%) over two years, 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. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the Minnesota Public Utilities Commission (MPUC) reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025.

In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. The procedural schedule is as follows:

• Intervenor direct testimony: August 22, 2025
• Rebuttal testimony: October 10, 2025
• Administrative Law Judge (ALJ) Report: April 30, 2026
• MPUC Decision: July 31, 2026

NSP-Minnesota — 2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the South Dakota Public Utilities Commission 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 has requested 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.

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. NSP-Minnesota will address these proposals in rebuttal testimony in the third quarter of 2025. 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 testimony asserting that no more than $6 million of customer refunds are warranted for the outage.

In July 2025, intervenor testimony was filed by the Minnesota Department of Commerce (DOC), the Office of the Minnesota Attorney General (OAG), and an association of large power customers (XLI). These parties, together with the Citizens Utility Board of Minnesota (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 the most recent DOC and OAG recommendations are applied to both 2023 and 2024, NSP-Minnesota estimates that the customer refunds would be approximately $34 million.

Rebuttal testimony is due in August 2025, with an ALJ report expected in March 2026 and an MPUC decision expected in the second quarter of 2026.

NSP-Minnesota — 2024 Minnesota Resource Plan Settlement — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the resource plan, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.

In February 2025, the MPUC approved the terms of the settlement agreement, including:

• The selection of the company owned 420 MW Lyon County combustion turbine.
• The selection of the company owned 300 MW 4-hour Sherco battery energy storage system.
• Multiple Power Purchase Agreements (PPAs) to proceed to the negotiation stage.
• The addition of 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.
• Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s.

Additionally, the MPUC approved life extensions of the Red Wing and Mankato RDF plants to 2037 and ordered NSP-Minnesota to file a proposed tariff for customers with super-large load, largely data centers, which was filed in July 2025.

NSP-Minnesota will file additional RFPs for approved resource needs beginning in late 2025 or early 2026.

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%.

The procedural schedule is as follows:

• Intervenor direct testimony: August 8, 2025
• Rebuttal testimony: August 28, 2025
• Hearing: September 16, 2025

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:

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

The CPUC verbally approved the settlement agreement without modification in June 2025, and a written decision is expected in the third quarter of 2025.

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.

Bids from the RFP were received in January 2025. In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:

SPS expects to make Certificate of Convenience and Necessity filings for the specific assets with the Public Utilities Commission of Texas (PUCT) and NMPRC in the second half of 2025, with approvals expected in 2026.

SPS will issue a second RFP in the second half of 2025 to solicit a minimum of 500 MW of accredited capacity through 2032, inclusive of additional renewable generation for New Mexico Renewable Portfolio Standard compliance.

SPS — System Resiliency Plan — In December 2024, SPS filed its Texas SRP with the PUCT. Consistent with PUCT requirements, SPS’ proposed plan discusses resiliency-related risks and the five measures that have been designed to help SPS prevent, withstand, mitigate or more promptly recover from resiliency events, including wildfire. The proposed SRP covers 2025-2028 and includes a proposed $538 million of investment.

In April 2025, SPS filed a unanimous stipulation and settlement agreement. The settlement includes approximately $490 million of spend over the plan period, adjusted largely to reflect the removal of the operational flexibility measure for investment in the normal course of business. The settlement also includes the deferral of distribution-related costs, including depreciation expense and carrying costs at SPS’ weighted average cost of capital.

In July 2025, the PUCT approved the SRP, authorizing approximately $495 million of spend over the plan period, including reinstating previously removed distribution hardening projects.

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. SPS has requested commission decisions by September 2025.

Note 5. Wildfire 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.

SPS is aware of approximately 27 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints 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 27 complaints, seven have been resolved and dismissed to date, with four others settled and pending dismissal. SPS has also received approximately 253 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 187 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 claims related to the Smokehouse Creek Fire Complex which have not been submitted through the claims process and have also not been filed as lawsuits, and has reached settlement of a portion of those claims. SPS anticipates additional complaints and demands will be made. SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex and has reached a settlement in principle with the subrogated insurer plaintiffs.

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.

Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy believes it is probable that it will incur a loss in connection with the Smokehouse Creek Fire Complex and accordingly has recorded $290 million of total estimated losses for the matter (before available insurance). Evaluation of the cost and other attributes of completed and anticipated claim settlements for various types of property damage, including certain previously inestimable categories of claims, resulted in an increase in total estimated losses relative to the $215 million estimate as of Dec. 31, 2024.

Settlements reached as of the date of this filing, including the settlement in principle with the subrogated insurer plaintiffs, total $176 million of expected loss payments, of which $123 million and $35 million were paid through June 30, 2025 and Dec. 31, 2024, respectively. A remaining estimated liability of $167 million and $180 million is presented in other current liabilities as of June 30, 2025 and Dec. 31, 2024, respectively.

The cumulative estimated probable losses of $290 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) corresponds to the lower end of the range of Xcel Energy’s reasonably estimable range of losses, and is subject to change based on additional information. This $290 million estimate does not include, among other things, 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. 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.

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 $221 million and $210 million, net of recoveries received are presented in prepayments and other current assets as of June 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.

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. 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 an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

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.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.

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 September 2023, the Boulder County District Court Judge consolidated the pending lawsuits into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025.

In September 2024, the Judge presiding over the consolidated cases in Boulder County issued an order regarding the trial that resolves, on a preliminary basis, certain disputes over the structure of the September 2025 trial. The Court ruled that all Plaintiffs should be bound by a trial on liability unless they opt-out with good cause. The Court also ruled that liability and damages should be largely or entirely tried separately, meaning that common questions of law and fact regarding liability would be decided first, and a majority or all of the damages phase will occur separately following the liability phase of trial. The individual plaintiffs filed a motion for reconsideration of the opt-out portion of this order, which the Court denied in November 2024, confirming that plaintiffs will have to demonstrate good cause in order to opt out of the trial. The Court also denied PSCo’s request for a change in venue, ruling that the trial will take place in Boulder County. In June 2025, the Court dismissed Xcel Energy, Inc. from the complaints that named that entity as a defendant, due to lack of jurisdiction.

Expert discovery in the case is ongoing. In addition to the Sheriff’s Report conclusions that PSCo’s power lines likely caused the second ignition and that an underground coal fire was a possible cause of the second ignition, two other theories about the cause of the second ignition have been put forth by various plaintiffs in expert reports that were submitted in the first quarter of 2025. The first is that partially unattached telecommunications equipment contacted PSCo’s power lines, and the second is that an unidentified flying object struck PSCo’s power lines.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.

Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action filed before Jan. 1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.

In the event PSCo or Xcel Energy Services Inc. was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million (of which approximately $400 million of coverage remains after consideration of legal costs incurred through June 30, 2025) and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, PSCo and Xcel Energy Services Inc. are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

Note 6. 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 increase ~1%.
• Capital rider revenue is projected to increase $255 million to $265 million (net of PTCs). The update is primarily driven by earnings neutral changes, largely due to O&M recovery of wildfire mitigation program spend.
• O&M expenses are projected to increase ~4%. The increase from prior guidance primarily driven by earnings neutral changes, largely due to O&M recovery in capital rider revenue for wildfire mitigation program spend.
• Depreciation expense is projected to increase approximately $210 million to $220 million.
• Property taxes are projected to increase $45 million to $55 million.
• Interest expense (net of AFUDC - debt) is projected to increase $160 million to $170 million, net of interest income.
• AFUDC - equity is projected to increase $110 million to $120 million.

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 $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).
• Deliver annual dividend increases of 4% to 6%.
• Target a dividend payout ratio of 50% to 60%.
• Maintain senior secured debt credit ratings in the A range.

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