News Details

MINNEAPOLIS--(BUSINESS WIRE)-- Xcel Energy Inc. (NASDAQ: XEL) today reported 2025 GAAP diluted earnings of $2.02 billion, or $3.42 per share, compared with $1.94 billion, or $3.44 per share in the same period in 2024 and ongoing earnings of $2.24 billion, or $3.80 per share, compared with $1.97 billion, or $3.50 per share in the same period in 2024. See Note 6 for reconciliation from GAAP to ongoing earnings.

The change in ongoing earnings reflect increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation and operating & maintenance expenses.

“In 2025, Xcel Energy delivered on our earnings guidance for the 21^st year in a row - one of the best track records in the industry. We placed in service critical infrastructure to serve our customers, including Phase 2 of our Sherco Solar facility, the conversion of our Harrington coal plant to natural gas, and the first two segments of our Colorado Power Pathway. All the while, our customers continue to have some of the lowest energy bills in the country,” said Bob Frenzel, chairman, president and CEO of Xcel Energy.

“As we look forward into 2026, we recently announced another large data center customer. We also announced two strategic alliances with industry-leading development and supply chain partners to help ensure we have the right resources to deliver critical system investments affordably, accelerate data center development for the benefit of all of our customers, and drive innovation. We are excited for the future and to make energy work better for our customers and communities.”

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 following the event.

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, 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; physical and financial 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; 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.

Note 1. Earnings Per Share Summary

Xcel Energy’s 2025 GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024. The change in ongoing earnings per share was driven by increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation and O&M expenses. 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). See Note 6 for reconciliation of GAAP earnings to ongoing earnings.

Summarized diluted EPS for Xcel Energy:

NSP-Minnesota — GAAP earnings increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024. Ongoing earnings increased due to higher recovery of electric infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges. See Note 6 for reconciliation from GAAP to ongoing earnings.

PSCo — GAAP earnings decreased $0.24 per share and ongoing earnings increased $0.14 per share for 2025 (difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Note 6 for reconciliation from GAAP to ongoing earnings). Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M charges.

SPS — GAAP and ongoing earnings decreased $0.03 per share for 2025. The decrease was driven by increased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher recovery of electric infrastructure investments.

NSP-Wisconsin — GAAP and ongoing earnings increased $0.03 per share for 2025. The increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially 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 due to gains on debt repurchases, partially offset by higher interest rates and debt levels.

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

ROE for Xcel Energy and its utility subsidiaries:

See Note 6 for reconciliation of GAAP earnings to ongoing earnings.

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 in 2025 compared to 2024:

Annual weather-normalized and leap-year adjusted electric sales growth (decline)

• NSP-Minnesota — Residential sales increased due to customer growth (1.1%) and use per customer (0.4%). The decrease in C&I sales was due to lower use per customer.
• PSCo — Residential sales increased due to customer growth (1.1%) and use per customer (0.6%). The increase in C&I sales was due to higher use per customer, particularly in the information and energy sectors.
• SPS — Residential sales increased due to increased use per customer (3.6%) and customer growth (0.7%). The increase in C&I sales was due to higher use per customer, primarily driven by the energy sector.
• NSP-Wisconsin — Residential sales increased due to increased use per customer (1.1%) and customer growth (0.9%). The increase in C&I sales was due to customer growth.

Annual weather-normalized and leap year adjusted natural gas sales growth (decline)

• Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all 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 (wind, nuclear, and solar), 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 $173 million in 2025. The increase is primarily due to increased commodity prices and transmission expense.

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 $90 million in 2025. The increase is primarily due to increased commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.

O&M Expenses — O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs.

Depreciation and Amortization — Depreciation and amortization increased $209 million for the year, primarily related to system investment.

Other Income — Other income increased $92 million for the year, primarily related to gains on debt repurchases.

Interest Charges — Interest charges increased $213 million in 2025. The increase was largely due to higher long-term and short-term debt levels and higher interest rates.

AFUDC, Equity and Debt — AFUDC increased $165 million in 2025, 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 Feb. 2, 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 assigned to Xcel Energy Inc. and its utility subsidiaries as of Feb. 2, 2026:

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

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)

2025 Financing Activity — During 2025, Xcel Energy and its utility subsidiaries issued the following long-term debt:

During the year ended Dec. 31, 2025, Xcel Energy Inc. issued shares through a combination of at-the-market cash settlements and physical settlement of certain forward sale agreements for a total of 48.3 million shares ($3.34 billion in net proceeds). Xcel Energy also entered into forward equity agreements and collared forward equity agreements of which 27.2 million shares remain contracted (minimum expected proceeds of $2.02 billion).

2026 Planned Financing Activities — During 2026, Xcel Energy Inc. and its utility subsidiaries anticipate the following long-term debt issuances:

In addition, Xcel Energy plans to issue incremental equity throughout 2026 through its at-the market program or other offerings. 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 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. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations.

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. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%.

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%. Interim rates were implemented 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 $45 million (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).

In November 2025, NSP-Minnesota filed a settlement agreement along with NDPSC Staff, which would increase the revenue requirement by approximately $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. A NDPSC decision on the settlement and implementation is anticipated in early 2026.

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. NSP-Minnesota requested interim rates of $12 million effective April 1, 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 $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 requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. A MPUC decision is expected in the fourth quarter of 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. Both the electric and natural gas rate requests are based on forward-looking 2026 and 2027 test years, with a 10.0% ROE and an equity ratio of 53.5%.

In December 2025, the PSCW issued final written approval on NSP-Wisconsin’s request, with a final rate increase of $126 million for the electric utility ($68 million in 2026, with an incremental $58 million in 2027) and $22 million for the natural gas utility ($18 million in 2026, with an incremental $4 million in 2027), based on a ROE of 9.8% and an equity ratio of 52.5%.

NSP System — Resource Acquisition — In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an 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. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar + storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota’s Distributed Solar Energy Standard eligibility requirements. Bids are due in March 2026, and filing for MPUC approval is expected by the end of 2026, ahead of the established procedural schedule.

PSCo — 2025 Colorado Electric Rate Case — In November 2025, PSCo filed an electric rate case with the Colorado Public Utility 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.

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.

A CPUC decision and implementation of final rates is anticipated in the third 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 a 3% compound annual sales growth through 2031 and generation capacity need of approximately 5,400 MW.

PSCo filed a request for reconsideration of various aspects of the decision which were verbally approved in January 2026 with a written decision related to those reconsideration requests expected in the first quarter of 2026. This decision is expected to initiate the Phase II competitive solicitation process with an RFP 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 any approved acquisitions from the Near-Term Procurement RFP).

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 nameplate MW of clean energy resources, 200 accredited MW of firm, dispatchable resources, and up to 300 accredited MW of other dispatchable resources.

The table below summarizes the recommended portfolio of resources filed in December 2025 (a decision is expected in February 2026):

SPS — 2025 New Mexico Electric Rate Case — In November 2025, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC) seeking a revenue increase of $175 million (16.7%). The request is based on a future test year period ending November 30, 2027, a ROE of 10.5%, an equity ratio of 56% and retail rate base of $3.9 billion.

The request reflects:

• Significant retail revenue growth.
• Continued capital investment primarily to support the clean energy transition and load growth.
• Planned roll-off of 100 MW of wholesale load in 2026.

The procedural schedule is as follows:

• Intervenor direct testimony: March 27, 2026
• Rebuttal testimony: April 17, 2026
• Public Evidentiary Hearing: May 26 - June 5, 2026

A NMPRC decision and implementation of final rates is anticipated in the second half of 2026.

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.

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 with 3,121 MW of accredited capacity resources, including the following:

SPS filed or expects to file Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025 and 2026, with approvals expected in 2026 and 2027.

SPS — 2025 Resource Acquisition — In October 2025, SPS issued a 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 were received in January 2026, and the portfolio is expected to be filed in the second half of 2026.

Note 5. Wildfire Litigation

Marshall Wildfire Litigation —In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire). 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 received notice or otherwise became aware of 307 complaints on behalf of at least 4,087 plaintiffs, most of which also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints generally alleged that PSCo’s equipment ignited the Marshall Fire and asserted various causes of action under Colorado law. In addition to asserting claims against PSCo, Xcel Energy Inc. and Xcel Energy Services Inc., 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, and require PSCo to make settlement payments of $640 million. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.

As a result of settlements as well as legal and other costs of the matter, PSCo recognized charges to earnings of $287 million and $12 million in the quarterly periods ended Sept. 30 and Dec. 31, 2025, respectively, after consideration of total costs expected to be reimbursed by insurance. As of February 2026, final settlement documentation has been executed with the subrogation insurers, the public entity plaintiffs and nearly all the individual plaintiffs, and nearly all have received payment. If complaints of the remaining individual plaintiffs who have not accepted a settlement or have otherwise stopped prosecuting their claims are not resolved, they may be subject to further litigation.

A remaining estimated liability of $5 million is presented in other current liabilities as of Dec. 31, 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 settlements are presented in prepayments and other current assets as of Dec. 31, 2025; no such insurance receivables were recognized as of Dec. 31, 2024.

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 47 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 47 complaints, 21 have been resolved and dismissed to date, with one other complaint settled and pending dismissal.

SPS has received 287 claims through its claims process, net of duplicative, withdrawn and denied claims, and has reached final settlements on 222 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 79 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 asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $382 million of expected loss payments, of which $374 million and $35 million were paid through Dec. 31, 2025 and 2024, respectively.

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.

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 $430 million of total estimated losses for the matter (before available insurance). A remaining estimated liability of $56 million and $180 million is presented in other current liabilities as of Dec. 31, 2025 and 2024, respectively.

The cumulative estimated probable losses of $430 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 $430 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 for estimated losses of approximately $195 million and $210 million, net of recoveries received are presented in prepayments and other current assets as of Dec. 31, 2025 and 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, 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)

Reconciliation of GAAP earnings (net income) to ongoing earnings:

Reconciliation of GAAP EPS to ongoing EPS by operating company:

Adjustments to GAAP net income include:

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. In the fourth quarter of 2025, an additional $12 million was recognized for estimated remaining settlement costs as well as legal and other costs. See Note 5.

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 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 $535 million to $545 million.
• O&M expenses are projected to increase ~3%.
• Depreciation expense is projected to increase approximately $350 million to $360 million.
• Property taxes are projected to increase $30 million to $40 million.
• Interest expense (net of AFUDC - debt) is projected to increase $300 million to $310 million, net of interest income.
• AFUDC - equity is projected to increase $140 million to $150 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.