Xcel Energy Second Quarter 2026 Earnings Report

• Second quarter diluted GAAP and ongoing earnings per share were $0.93 in 2026 compared with $0.75 in 2025.
• Year-to-date diluted GAAP earnings per share were $1.82 in 2026 compared with $1.59 in 2025.
• Year-to-date diluted ongoing earnings per share were $1.84 in 2026 compared with $1.59 in 2025.
• Xcel Energy reaffirms its 2026 ongoing earnings per share guidance of $4.04 to $4.16.

MINNEAPOLIS--(BUSINESS WIRE)-- Xcel Energy Inc. (NASDAQ: XEL) today reported 2026 second quarter GAAP earnings of $586 million, or $0.93 per share, compared with $444 million, or $0.75 per share in the same period in 2025 and ongoing earnings of $589 million, or $0.93 per share compared with $444 million or $0.75 per share in the same period in 2025. See Note 6 for reconciliation from GAAP to ongoing earnings.

The change in earnings per share was primarily driven by increased recovery of electric infrastructure investments, partially offset by higher financing costs.

“Xcel Energy has been at the center of transformations and infrastructure shifts in our industry for more than 100 years. Our second quarter results demonstrate strong and consistent execution across all our key priorities: customer satisfaction and affordability, system reliability and resiliency, meeting the clean energy aspirations of our communities and ensuring financial discipline,” said Bob Frenzel, chairman, president and CEO of Xcel Energy.

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 for one week.

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 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, 2025 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; risks associated with wildfires; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; reputational impacts of actions by employees, directors, or third-parties; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; risks associated with the growth of large load 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 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 second quarter diluted GAAP and ongoing earnings were $0.93 per share compared with $0.75 per share in the same period in 2025. The change in earnings per share was primarily driven by increased recovery of electric infrastructure investments, partially offset by higher financing costs. 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 $0.06 per share for the second quarter of 2026. Year-to-date GAAP earnings increased $0.03 per share and ongoing earnings increased $0.01 per share. The increase in year-to-date ongoing earnings was driven by higher recovery of electric infrastructure investments which was partially offset by unfavorable weather. The difference between GAAP and ongoing earnings was driven by an increase in the estimated amount recoverable from insurance for Marshall Wildfire costs (See Note 6).

NSP-Minnesota — GAAP and ongoing earnings increased $0.05 per share for the second quarter of 2026. Year-to-date GAAP earnings increased $0.03 per share and ongoing earnings increased $0.07 per share. 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 interest charges. The difference between GAAP and ongoing earnings was driven by recognition of customer refunds related to the 2023-2024 Prairie Island nuclear facility outage (See Note 6).

SPS — GAAP and ongoing earnings increased $0.02 per share for the second quarter and $0.06 per share year-to-date. The year-to-date change was driven by sales growth and higher recovery of electric infrastructure investments, partially offset by increased depreciation expense.

NSP-Wisconsin — GAAP and ongoing earnings increased $0.01 per share for the second quarter and $0.05 year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation expense and interest charges.

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 unrealized gains on the investment funds’ interests in energy technology companies, partially offset by higher debt levels.

Components significantly contributing to changes in 2026 EPS compared to 2025:

Note 2. Regulated Utility Results

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanisms 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 volumes in 2026 compared to 2025:

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

• C&I sales — Increase is due to higher use per customer in SPS (6.0%) and NSP-Minnesota (2.0%) and customer growth in NSP-Wisconsin (1.0%). Increased activity in the energy sector in SPS and the manufacturing sector in all jurisdictions contributed to the sales growth.

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

• Decrease in natural gas sales was driven primarily by reduced use per customer in most jurisdictions and customer classes.

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 decreased $240 million for the second quarter of 2026 and $241 million year-to-date. The year-to-date change was primarily due to lower commodity prices, largely in SPS.

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 $41 million for the second quarter of 2026 and $34 million year-to-date. The year-to-date change was primarily due to decreased volumes in PSCo, partially offset by higher commodity prices.

O&M Expenses — O&M expenses increased $16 million for the second quarter of 2026 and $5 million year-to-date. The year-to-date change was primarily due to increased generation costs.

Depreciation and Amortization — Depreciation and amortization decreased $60 million for the second quarter of 2026 and $20 million year-to-date. The year-to-date change was primarily due to the recognition of 2025 and 2026 depreciation reductions (nuclear life extensions) in the second quarter of 2026, partially offset by system expansion.

Interest Charges — Interest charges increased $94 million for the second quarter of 2026 and $174 million year-to-date. The year-to-date change was primarily due to higher debt levels.

Earnings from Equity Method Investments — Earnings from equity method investments increased $84 million for the second quarter of 2026 and $98 million year-to-date. The year-to-date change was primarily due to unrealized gains on investment funds’ interests in energy technology companies in the first six months of 2026 and losses in the first six months of 2025.

AFUDC, Equity and Debt — AFUDC increased $54 million for the second quarter of 2026 and $115 million year-to-date. The year-to-date change was primarily due to 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, 2026, 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, 2026:

2026 Financing Activity — During 2026, Xcel Energy Inc. and its utility subsidiaries issued or plan to issue the following long-term debt:

During the six months ended June 30, 2026, Xcel Energy Inc. entered forward sale agreements totaling 42.5 million shares (minimum expected proceeds of $3.2 billion). There were no shares issued in at-the-market cash transactions or settlements of forward sale agreements during the period. As of June 30, 2026, 69.7 million shares remain unsettled on forward sale agreements (minimum expected proceeds of $5.2 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 Minnesota 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 Minnesota Public Utilities Commission (MPUC) approved interim rates of $192 million, effective Jan. 1, 2025. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million.

In June 2026, the MPUC issued a verbal decision. Terms of the decision include:

• Estimated rate increase of approximately $211 million over two years (annual average increase of 2.9%).
• ROE of 9.60%, an increase from the current 9.25% ROE, while maintaining the equity ratio of 52.5%.
• Continuation of existing true-up mechanisms inclusive of the sales true-up, coupled with authorization of new tracker mechanisms.

A final written MPUC order is expected by July 31, 2026.

NSP-Minnesota - 2025 Minnesota Natural Gas Rate Case — In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $62 million (8.2%) as updated in April 2026. 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 requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC.

In May 2026, NSP-Minnesota and certain intervenors reached a non-unanimous settlement, based on a total revenue increase of $38 million (4.9%) and a weighted average cost of capital of 7.21% (an increase from the previously authorized 7.16%).

An Administrative Law Judge (ALJ) report is expected by September 2026 and a MPUC decision is expected in November 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%, an equity ratio of 52.87% and rate base of approximately $1.2 billion. Interim rates were implemented on Jan. 1, 2026.

In April 2026, NSP-Minnesota and SDPUC Staff filed a black box settlement agreement with the SDPUC, including a net annual electric rate increase of $26 million. In May 2026, the SDPUC approved the settlement agreement, and rates became effective July 1, 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 March 2026, the ALJ recommended a $41 million disallowance of estimated replacement power costs. In May 2026, the MPUC ordered a $41 million disallowance, consistent with the ALJ recommendation. NSP-Minnesota recognized an incremental $37 million in customer refunds, including interest, to electric revenues in the first quarter of 2026. Incremental interest was recognized in the second quarter of 2026 (see Note 6 for further information).

NSP-Minnesota — 2026 North Dakota Natural Gas Rate Case — In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. In March 2026, the North Dakota Public Service Commission approved interim rates of $12 million effective April 1, 2026. The procedural schedule is yet to be determined.

NSP System — Resource Acquisition — In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued a Request for Proposal (RFP) seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Short-listed projects were announced in June 2026, and filing for requisite regulatory approval is expected by the end of 2026.

NSP System — Large Load Agreement — In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the contract, in accordance with Minnesota’s regulatory and legislative requirements for large loads. If approved, the agreement is expected to result in approximately $1.1 billion of benefits to NSP-Minnesota’s customers. A request for approval of the electric service agreement, including a proposed Clean Energy Accelerator Charge for 1,900 MW of clean energy resources, was filed with the MPUC in April 2026. A decision is expected in early 2027.

Approvals for 1,000 MW of resources for the Clean Energy Accelerator program are pending as part of existing resource acquisition processes. The remaining resources are expected to be requested in those processes by the end of 2026.

PSCo — 2025 Colorado Electric Rate Case — In November 2025, PSCo filed an electric rate case with the Colorado Public Utilities Commission (CPUC) seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins). The request is based on a 9.8% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $13 billion.

In June 2026, PSCo, CPUC Staff and various other parties filed a comprehensive non-unanimous settlement agreement. The AARP, City of Boulder and the Colorado Office of Utility Consumer Advocate (UCA) oppose the settlement. Other parties either support portions of the settlement or do not oppose it. Terms of the settlement include:

• Revenue increase (excluding rider roll-ins) of $225 million (6.3% total, or an annual average of 2.05% since the last rate case), based on a 2025 historic test year using year-end rate base with limited forward looking known and measurable adjustments.
• ROE of 9.3% and equity ratio of 54.5%.
• A performance framework applicable to the operation of Comanche Unit 3 coal facility from effective date of rates through 2029.
• Transfer of the previous Transmission Cost Adjustment investments into rate base.
• Continuation of previously authorized trackers and deferrals.

A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.

PSCo — 2025 Colorado Natural Gas Rate Case — In December 2025, PSCo filed a natural gas rate case with the CPUC seeking an increase in revenue of $190 million (11.6%). The request is based on a 10.75% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $4.7 billion.

In July 2026, PSCo, CPUC Staff, the UCA, the Colorado Energy Office, Western Resource Advocates/Sierra Club, Energy Outreach Colorado and various other parties filed a comprehensive non-unanimous settlement agreement. Several parties either do not oppose or take no position on the settlement, and one transportation shipper opposes it. Key terms of the settlement include:

• Revenue increase of $123 million (7.5% total, or an annual average of 3.7% since the last rate case), based on a 2025 historic test year using average rate base with forward looking known and measurable adjustments.
• ROE of 9.2% and equity ratio of 54.5%.

Hearings to discuss the settlement took place in July 2026. A CPUC decision and implementation of final rates is anticipated in the fourth quarter of 2026.

PSCo — 2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a load forecast that reflects 3% compound annual sales growth through 2031 and a generation capacity need of approximately 5,400 MW.

PSCo filed a request for reconsideration of various aspects of the decision which were approved in February 2026. The RFP for the Phase II competitive solicitation process is expected to be issued in the third quarter of 2026. This RFP will seek to acquire the balance of resource needs through 2031 (after consideration of 3,800 MW of approved acquisitions from the Near-Term Procurement RFP).

SPS — 2025 New Mexico Electric Rate Case — In November 2025, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC). As updated in March 2026, SPS requested a revenue increase of $168 million (16.0%). The request was based on a future test year period ending Nov. 30, 2027, a ROE of 10.5%, an equity ratio of 56% and retail rate base of $3.9 billion.

In June 2026, SPS, New Mexico Department of Justice, New Mexico Large Customer Group and various other parties filed a comprehensive non-unanimous stipulation. NMPRC Staff opposes certain components of the stipulation.

Terms of the stipulation include:

• Base rate revenue increase of $90 million (7.7% total, or an annual average of 2.4% since the last rate case), based on the filed future test year.
• ROE of 9.5%.
• Equity ratio of 54.70%.

A hearing on the non-unanimous stipulation took place in July 2026. An NMPRC decision is anticipated in the fourth quarter of 2026, with implementation of rates expected in December 2026.

SPS — SPS Resource Acquisition — In October 2023, SPS filed its Integrated Resource Plan with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources.

In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited capacity by 2030. In July 2025, the portfolio selection report was publicly filed with the NMPRC. SPS has received NMPRC approval of the Certificate of Convenience and Necessity (CCN) filings for the specific assets, and PUCT approval is expected in the third quarter. SPS is continuing to pursue approximately 2,800 MW of accredited resources, including approximately 4,000 MW of nameplate capacity company owned resources and approximately 500 MW of nameplate capacity Power Purchase Agreements (PPAs).

In October 2025, SPS issued a RFP to solicit 870 MW of accredited capacity through 2032 (approximately 1,500 MW to 3,000 MW nameplate capacity, or more depending on resource mix), with additional resources to be evaluated to meet the New Mexico Renewable Portfolio Standard (RPS) compliance need. Bids were received in January 2026, and the portfolio selection report was publicly filed with the NMPRC in July 2026. Project CCNs are expected to be filed in late 2026 or early 2027. The following resources are included in SPS’ preferred portfolio:

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.

After reaching the generally applicable two-year statute of limitations for property damage in Texas, SPS is aware of approximately 73 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 73 complaints, 28 have been resolved.

SPS has received 304 claims through its claims process, net of duplicative, withdrawn and denied claims, and has reached final settlements on 237 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 107 additional claims and has reached settlement of 79 of those claims through mediation.

In December 2025, the Texas Attorney General’s office filed a lawsuit against SPS regarding the Smokehouse Creek Fire, seeking monetary damages and civil penalties for losses to property and wildlife resulting from the fires. In February 2026, pending resolution of the lawsuit, SPS and the Texas Attorney General’s office jointly filed a temporary injunction agreeing to certain distribution pole replacement procedures, largely consistent with current procedures.

SPS has settled claims related to both 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 asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $404 million of expected loss payments, of which $398 million and $374 million were paid through June 30, 2026 and Dec. 31, 2025, 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 $56 million of remaining estimated probable losses for the matter (before available insurance), for a total estimated loss of $460 million. Additionally, approximately $43 million in legal costs have been incurred as of June 30, 2026, resulting in total estimated losses and incurred costs related to this proceeding of $503 million as of June 30, 2026. An estimated liability of $62 million and $56 million for estimated losses is presented in other current liabilities as of June 30, 2026 and Dec. 31, 2025, respectively.

The estimated remaining probable losses for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the low end of the range for remaining reasonably estimable losses and is subject to change as additional information becomes available. This 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 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 the nature of demands that may be made. Resolution of remaining complaints and claims associated with the Smokehouse Creek Fire Complex could exceed our insurance coverage of $525 million for the annual policy period (of which approximately $80 million of coverage remains after consideration of settlements reached and legal costs incurred through June 30, 2026) 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 for estimated losses of approximately $81 million and $195 million, net of recoveries received are presented in prepayments and other current assets as of June 30, 2026 and Dec. 31, 2025, 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 occurred in Boulder County, Colorado (Marshall Fire). According to a 2023 report of the Boulder County Sheriff, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado for reasons unrelated to PSCo’s power lines. Also according to the 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, approximately 80 to 110 feet away from PSCo’s power lines in the area.

PSCo received complaints alleging that PSCo’s equipment ignited the Marshall Fire and asserted various causes of action under Colorado law. In addition to asserting claims against PSCo and certain of its affiliates, various plaintiffs asserted claims against certain telecommunications companies.

In September 2025, Xcel Energy and other defendants reached settlement agreements in principle that resolved all claims and required PSCo to make settlement payments of $640 million. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements. As of July 2026, settlements have been executed with all plaintiffs and subrogation insurers.

As a result of settlements as well as legal and other costs of the matter, PSCo recognized charges to earnings of $298 million in the year ended Dec. 31, 2025, after consideration of total costs expected to be reimbursed by insurance. In 2026, PSCo increased its estimated amount recoverable from insurance, contributing to a net $19 million credit to earnings for the six months ended June 30, 2026 (see Note 6 for further information).

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 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:

Prairie Island Outage Refunds — As further discussed in Note 4, in March 2026, the ALJ recommended a disallowance of $41 million for estimated replacement power costs incurred during a 2023-2024 outage at NSP-Minnesota’s Prairie Island nuclear facility. The MPUC ordered the ALJ-recommended disallowance in May 2026. Total non-recurring charges of $38 million were recorded to electric revenues during the six months ended June 30, 2026 for incremental customer refunds, including interest.

Marshall Wildfire Litigation — As further discussed in Note 5, during the six months ended June 30, 2026, PSCo recognized $19 million of net reductions to operating expenses due primarily to an increase in the estimated amount recoverable from insurance for non-recurring Marshall Wildfire costs.

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

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 remainder of 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 $480 million to $490 million.
• O&M expenses are projected to increase ~3%.
• Depreciation expense is projected to increase approximately $140 million to $150 million. The decrease from prior guidance is primarily due to nuclear life extensions, which is offset by lower revenue.
• Property taxes are projected to increase $30 million to $40 million.
• Interest expense (net of AFUDC - debt) is projected to increase $240 million to $250 million, net of interest income.
• AFUDC - equity is projected to increase $150 million to $160 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 $3.80 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.

View source version on businesswire.com: https://www.businesswire.com/news/home/20260730823222/en/

For more information, contact:
Roopesh Aggarwal, Vice President - Investor Relations, (612) 215-4535
Xcel Energy website address: www.xcelenergy.com, (612) 215-5300

Source: Xcel Energy

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