THIRD QUARTER 2026 EARNINGS REPORT
• Third quarter diluted GAAP and ongoing earnings per share were $1.52 in 2026 compared with GAAP earnings of $0.88 and ongoing earnings of $1.24 in 2025.
• Year-to-date diluted GAAP earnings per share were $3.34 in 2026 compared with $2.47 in 2025.
• Year-to-date diluted ongoing earnings per share were $3.37 in 2026 compared with $2.84 in 2025. • Xcel Energy narrows its 2026 ongoing earnings per share guidance to $4.10 to $4.16.
• Xcel Energy initiates its 2027 ongoing earnings per share guidance of $4.48 to $4.62.
• Xcel Energy’s long-term annual growth objectives reflect earnings per share growth of 6-8+% and dividend growth of 4-6%.
MINNEAPOLIS — Xcel Energy Inc. (NASDAQ: XEL) today reported 2026 third quarter GAAP earnings of $960 million, or $1.52 per share, compared with $524 million, or $0.88 per share in the same period in 2025 and ongoing earnings of $961 million, or $1.52 per share compared with $737 million or $1.24 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, earnings on equity method investments and unseasonably warm weather, partially offset by higher financing costs.
“As one of the nation’s largest builders of clean generation and high-voltage transmission, Xcel Energy continues to make critical investments in the infrastructure our customers and communities need, while staying focused on delivering safe, clean, reliable and affordable energy.
We’ve made considerable progress on our priorities this quarter and our updated five-year investment plan gives us a clear path to extend this growth cycle and continue to deliver affordable and reliable energy our customers need well into the next decade,” 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. 1 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 and 2027 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.
Roopesh Aggarwal, Vice President - (612) 215-4535 Investor Relations Jessica Noren, Director - Investor (612) 330-5512 Relations Xcel Energy website address: www.xcelenergy.com (612) 215-5300
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.
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 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
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. 4
Xcel Energy’s third quarter diluted GAAP and ongoing earnings were $1.52 per share in 2026, compared with GAAP earnings of $0.88 per share and ongoing earnings of $1.24 in the same period in 2025. The change in ongoing earnings per share was primarily driven by increased recovery of electric infrastructure investments, earnings on equity method investments and unseasonably warm weather, 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).
— GAAP earnings increased $0.49 per share and ongoing earnings increased $0.13 per share for the third quarter of 2026. Year-to-date GAAP earnings increased $0.52 per share and ongoing earnings increased $0.14 per share. The increase in year-to-date ongoing earnings was driven by higher recovery of electric infrastructure investments and increased AFUDC, which was partially offset by increased interest charges and depreciation expenses. The difference between GAAP and ongoing earnings was driven by the impact of Marshall Wildfire litigation (See Note 6).
— GAAP and ongoing earnings decreased $0.02 per share for the third quarter of 2026. Year-to-date GAAP earnings increased $0.01 per share and ongoing earnings increased $0.05 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).
— GAAP and ongoing earnings increased $0.07 per share for the third quarter and $0.12 per share year-to-date. The year-to-date change was driven by sales growth, weather, and higher recovery of electric infrastructure investments, partially offset by increased depreciation expense and interest charges.
— GAAP and ongoing earnings increased $0.01 per share for the third quarter and $0.06 year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, partially offset by increased O&M expenses, depreciation expense and interest charges.
— 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. 5 Components significantly contributing to changes in 2026 EPS compared to 2025:
Diluted Earnings Three Months Nine Months (Loss) Per Share Ended Sept. 30 Ended Sept. 30 ────────────────────────────────────────────────────────────────────────────── GAAP EPS — 2025 $ 0.88 $ 2.47 Components of change - 2026 vs. 2025 Marshall Wildfire litigation (See 0.36 0.38 Note 6) Lower electric fuel and purchased 0.04 0.35 power Higher electric 0.32 0.32 revenues Higher AFUDC 0.11 0.29 equity and debt Higher earnings from equity method 0.09 0.21 investments Higher interest -0.13 -0.35 charges Common equity -0.10 -0.24 financing Higher O&M -0.08 -0.09 expenses Other, net 0.03 — GAAP EPS — 2026 $ 1.52 $ 3.34 Prairie Island outage refunds — 0.04 (See Note 6) Marshall Wildfire litigation (See — -0.02 Note 6) Ongoing EPS — $ 1.52 $ 3.37 2026(a)
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.
— Estimated impact of temperature variations on EPS compared with normal weather conditions:
— Sales growth (decline) for actual and weather-normalized sales volumes in 2026 compared to 2025:
• Residential sales — Increase is due to both customer growth and higher use per customer across jurisdictions.
• C&I sales — Increase is due to higher use per customer in SPS (5.6%) and NSP- Minnesota (2.8%) and customer growth in NSP-Wisconsin (0.9%). Increased activity in the energy sector in SPS and the manufacturing sector in all jurisdictions contributed to the sales growth.
• Decrease in natural gas sales was driven primarily by reduced use per customer in most jurisdictions and customer classes, partially offset by customer growth in all jurisdictions. 7
— 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.
Three Months Nine Months (Millions of Ended Sept. 30, Ended Sept. 30, Dollars) 2026 vs. 2025 2026 vs. 2025 ────────────────────────────────────────────────────────────────────────────── Non-fuel riders $ 93 $ 296 Sales and 42 111 demand Conservation and demand side management 29 70 (offset in expense) Wholesale 25 69 transmission Regulatory rate outcomes (CO, 88 68 MN, ND, SD and WI) Estimated impact of 50 39 weather (net of sales true-up) Recovery of higher (lower) cost of 11 -158 electric fuel and purchased power PTCs flowed back to customers -55 -114 (offset by ETR) Wholesale -41 -85 generation Prairie Island outage refunds — -38 (See Note 6) Other, net 8 -5 Total increase $ 250 $ 253
— Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.
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 $31 million for the third quarter of 2026 and $272 million year-to-date. The year-to-date change was primarily due to lower commodity prices, largely in SPS, as well as timing of fuel recovery mechanisms.
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 $3 million for the third quarter of 2026 and $37 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 increased $67 million for the third quarter of 2026 and $72 million year-to-date. The year-to-date change was primarily due to increased generation, wildfire mitigation and gas system costs.
— Depreciation and amortization increased $41 million for the third quarter of 2026 and $21 million year-to-date. The year-to-date change was primarily due to system expansion, partially offset by the recognition of 2025 and 2026 depreciation reductions (nuclear life extensions) in the second quarter of 2026.
— Interest charges increased $100 million for the third quarter of 2026 and $274 million year-to-date. The year-to-date change was primarily due to higher debt levels.
— Earnings from equity method investments increased $71 million for the third quarter of 2026 and $169 million year-to-date. The year-to-date change was primarily due to unrealized gains on investment funds’ interests in energy technology companies. 8
— AFUDC increased $68 million for the third quarter of 2026 and $183 million year-to-date. The year-to-date change was primarily due to system investment.
(a) Wind and Solar PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
(b) Regulatory adjustments for income tax primarily relate to the credit of excess deferred taxes to customers. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
Note 3. Capital Structure, Liquidity, Financing and Credit Ratings Xcel Energy’s capital structure:
— As of October 27, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
— 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. 9 Credit ratings and long-term outlook assigned to Xcel Energy Inc. and its utility subsidiaries as of October 28, 2026:
S&P Moody… Global Fitch Ratin… Comp… Credit Rating Outlo… Rating Outlook Rating Outlo… Type Xcel Ener… Unsec… Baa1 Negat… BBB Stable BBB+ Stable Inc. NSP-… Secur… Aa3 Stable A Stable A+ Stable NSP-… Secur… A1 Stable A Stable A+ Stable PSCo Secur… A1 Negat… A Negati… A+ Stable SPS Secur… A3 Stable A- Stable A- Stable Xcel Comme… Ener… paper P-2 A-2 F2 Inc. NSP-… Comme… P-1 A-2 F2 paper NSP-… Comme… P-2 A-2 F2 paper PSCo Comme… P-2 A-2 F2 paper SPS Comme… P-2 A-2 F2 paper
(a) Other category includes intercompany transfers for equipment with long lead times.
The plan does not include any potential incremental generation from the current generation RFPs across jurisdictions, investments to serve future large load customers or additional transmission investment that may come from future planning processes including MISO and SPP.
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. 10
— 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 2027-2031 (includes the impact of tax credit transferability):
(c) Amount could include other financing instruments that receive equity credit from the credit rating agencies.
— During 2026, Xcel Energy Inc. and its utility subsidiaries issued the following long-term debt:
In the third quarter of 2026, 10.5 million shares were issued (net proceeds of $819 million) in settlements of forward sale agreements or in at-the-market cash transactions.
During the nine months ended Sept. 30, 2026, Xcel Energy Inc. entered forward sale agreements totaling 62.1 million shares (minimum expected proceeds of $4.1 billion). As of Sept. 30, 2026, 79.4 million shares remain unsettled on forward sale agreements (minimum expected proceeds of $5.8 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.
NSP-Minnesota — Electric Rate Case Stay-Out Petition — On Oct. 9th, 2026, NSP- Minnesota filed an Electric Customer Rate Stability Plan with the Minnesota Public Utilities Commission (MPUC), as an alternative to the planned upcoming rate case filing.
• Accelerated recognition of federal Investment Tax Credit benefits related to five battery storage projects over two years. This acceleration will act as an offset to the incremental revenue requirement impact of ongoing necessary capital improvements.
• Continuation of other true-up and tracker mechanisms as approved in NSP- Minnesota’s most recent Electric Rate Case. A MPUC decision on the proposed Rate Stability Plan has been requested by January 2027. If not approved, NSP-Minnesota expects to file an electric rate case in early 2027. 11 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 October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. In July 2026, the MPUC issued a written order. Terms of the order include: • Rate increase of approximately $211 million over two years (annual average increase of 2.9%).
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%). In August 2026, the ALJ issued their report. A MPUC decision is expected in the fourth quarter of 2026.
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.
In October 2026, NSP-Wisconsin announced that it has entered into agreements to sell its approximately $150 million of Michigan electric and gas assets to Upper Peninsula Power Company and SEMCO ENERGY Gas Company, respectively, contingent on approvals of the Michigan Public Service Commission, Public Service Commission of Wisconsin and the Federal Energy Regulatory Commission. NSP- Wisconsin and the buyers plan to file requests for regulatory approvals by the end of 2026, with the transactions anticipated to close in 2027. The timing and amount of the gain for the transactions will be dependent on customary closing conditions and resolution of the regulatory approval processes.
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.
— 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 have been received as part of existing resource acquisition processes. The remaining resources are expected to be requested in those processes by the second quarter of 2027.
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. 12 In June 2026, PSCo, CPUC Staff and various other parties filed a comprehensive non-unanimous settlement agreement. The AARP, City of Boulder and the UCA opposed the settlement. Other parties either supported portions of the settlement or did not oppose it. PSCo received a final decision from the CPUC in September 2026. Terms of the final decision include:
• Revenue increase (excluding rider roll-ins) of $184 million (5.2% total, or an annual average of 1.7% since the last rate case), based on a 2025 historical test year using a 13-month average.
• 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. PSCo also agreed to file a prudence review related to the outage at the unit (from August 2025 to September 2026) in June 2027. • Continuation of previously authorized trackers and deferrals.
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 a 13-month average rate base with forward looking known and measurable adjustments.
• ROE of 9.2% and equity ratio of 54.5%. The CPUC approved the settlement agreement with minor modifications. Rates were implemented in October 2026.
— In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a revised load forecast methodology and authorized the Company to initiate its request for proposals. 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 was issued in the third quarter of 2026. This RFP is specifically seeking to acquire 500 MW of additional capacity by 2031 with potential upside for additional capacity as new large load customers are approved (after consideration of 3,800 MW of approved acquisitions from the Near-Term Procurement RFP). Bids are due in December 2026, and a CPUC decision is expected in the second half of 2027.
— 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.
• Equity ratio of 54.70%. A hearing on the non-unanimous stipulation took place in July 2026. On Oct. 23, 2026, SPS received the Hearing Examiners’ Report, which recommended NMPRC approval with certain minor modifications. Any exceptions are required to be filed by Nov. 2, 2026. An NMPRC decision is anticipated in the fourth quarter of 2026, with implementation of rates expected in December 2026.
— In October 2023, SPS filed its Integrated Resource Plan (IRP) with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. 13 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 filed for approval of 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). SPS has received NMPRC approval of the Certificate of Convenience and Necessity (CCN) filings for the assets. In October 2026, the PUCT approved the self build portfolio with the exception of the Plant X battery storage project. The approval includes performance and cost cap guarantees. SPS will be seeking rehearing on this decision.
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. The portfolio selection report was publicly filed with the NMPRC in July 2026, with a preferred portfolio that contains approximately 2,600 MW of nameplate capacity company owned resources and approximately 1,300 MW of nameplate capacity PPAs. Project CCNs are expected to be filed in early 2027.
— In October 2026, SPS filed its 2026 IRP with the NMPRC, which demonstrates projected load growth and shows energy and capacity resource portfolio needs under three different load forecast scenarios. Based on these forecast scenarios and the progress of existing resource acquisition processes, SPS' initial IRP modeling identified resource needs of approximately 2,000 MW of incremental accredited capacity by 2034. Following NMPRC action on the IRP, SPS expects to issue a competitive all-source solicitation for new generation in mid-2027 with project selection expected in early 2028.
— 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 outstanding complaints and claims representing an estimated 141 plaintiff groups (for example, members of the same family and any associated business, or affiliated corporations). 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. The generally applicable two-year statute of limitations for property damage in Texas was reached in March 2026.
In total, SPS has settled 358 complaints and claims related to the fire. 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 $410 million of expected loss payments, of which $405 million and $374 million were paid through Sept. 30, 2026 and Dec. 31, 2025, 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. 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. The Texas Attorney General’s claims are in the discovery phase, which is anticipated to continue into 2027.
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 $65 million of remaining estimated probable losses for the matter (before available insurance), for a total estimated loss of $475 million. Additionally, approximately $50 million in legal costs have been incurred as of Sept. 30, 2026, resulting in total estimated losses and incurred costs related to this proceeding of $525 million as of Sept. 30, 2026. An estimated liability of $70 million and $56 million for estimated losses is presented in other current liabilities as of Sept. 30, 2026 and Dec. 31, 2025, respectively. 14 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 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 $96 million and $195 million, net of recoveries received are presented in prepayments and other current assets as of Sept. 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.
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.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
In a September 2024 decision, the MPUC ruled that NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in an extended 2023-2024 outage. In May 2026, the MPUC ordered a disallowance of $41 million for estimated replacement power costs incurred during the outage. Total non-recurring charges of $38 million were recorded to electric revenues during the nine months ended Sept. 30, 2026 for incremental customer refunds, including interest. 15
— In September 2025, Xcel Energy and other defendants reached settlement agreements in principle that resolved all claims relating to the 2021 Marshall Wildfire. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlements. During the three months ended Sept. 30, 2025, PSCo recognized a non-recurring $287 million charge as a result of the settlement.
During the nine months ended Sept. 30, 2026, PSCo recognized $18 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.
— Xcel Energy’s 2026 ongoing earnings guidance is a narrowed range of $4.10 to $4.16 per share, from the original guidance of $4.04 to $4.16 per share. (a)
• Capital rider revenue is projected to increase $370 million to $380 million. The decrease from prior guidance is primarily offset by depreciation and AFUDC impacts.
• Depreciation expense is projected to increase approximately $100 million to $110 million. The decrease from prior guidance is primarily offset by lower revenue.
• Interest expense (net of AFUDC - debt) is projected to increase $290 million to $300 million, net of interest income.
• AFUDC - equity is projected to increase $180 million to $190 million. The increase from prior guidance is primarily offset by lower revenue.
Xcel Energy’s 2027 ongoing earnings guidance is a range of $4.48 to $4.62 per share. (a)
• Weather-normalized retail firm natural gas sales are projected to increase ~1%.
• Depreciation expense is projected to increase approximately $460 million to $470 million.
• Interest expense (net of AFUDC - debt) is projected to increase $320 million to $330 million, net of interest income.
(a) Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
— 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:
Three Months Ended Sept. 30 Operating revenues: 2026 2025 ────────────────────────────────────────────────────────────────────────────── Electric and natural gas $ 4,160 $ 3,902 Other 12 13 Total operating revenues 4,172 3,915 Net income $ 960 $ 524 Weighted average diluted common shares 632 595 outstanding Components of EPS — Diluted Regulated utility $ 1.52 $ 0.96 Xcel Energy Inc. and — -0.07 other costs GAAP diluted EPS(a) $ 1.52 $ 0.88 Marshall Wildfire settlement (See Note — 0.36 6) Ongoing diluted EPS(a) $ 1.52 $ 1.24 Book value per share $ 40.32 $ 35.59 Cash dividends declared 0.5925 0.57 per common share
Nine Months Ended Sept. 30 Operating revenues: 2026 2025 ────────────────────────────────────────────────────────────────────────────── Electric and natural $ 11,271 $ 11,066 gas Other 41 42 Total operating 11,312 11,108 revenues Net income $ 2,102 $ 1,451 Weighted average diluted common shares 629 587 outstanding Components of EPS — Diluted Regulated utility $ 3.44 $ 2.72 Xcel Energy Inc. and -0.10 -0.24 other costs GAAP diluted EPS(a) $ 3.34 $ 2.47 Prairie Island outage refunds (See Note 0.04 — 6) Marshall Wildfire settlement (See Note -0.02 0.36 6) Ongoing diluted EPS(a) $ 3.37 $ 2.84 Book value per share $ 40.56 $ 36.11 Cash dividends declared 1.7775 1.71 per common share
Full text with the tables
Exhibit 99.01
414 Nicollet Mall
October 29, 2026 Minneapolis, MN 55401
───────────────────────────────────────────
XCEL ENERGY
THIRD QUARTER 2026 EARNINGS REPORT
• Third quarter diluted GAAP and ongoing earnings per share were $1.52 in 2026
compared with GAAP earnings of $0.88 and ongoing earnings of $1.24 in 2025.
• Year-to-date diluted GAAP earnings per share were $3.34 in 2026 compared with
$2.47 in 2025.
• Year-to-date diluted ongoing earnings per share were $3.37 in 2026 compared
with $2.84 in 2025.
• Xcel Energy narrows its 2026 ongoing earnings per share guidance to $4.10 to
$4.16.
• Xcel Energy initiates its 2027 ongoing earnings per share guidance of $4.48 to
$4.62.
• Xcel Energy’s long-term annual growth objectives reflect earnings per share
growth of 6-8+% and dividend growth of 4-6%.
MINNEAPOLIS — Xcel Energy Inc. (NASDAQ: XEL) today reported 2026 third quarter
GAAP earnings of $960 million, or $1.52 per share, compared with $524 million,
or $0.88 per share in the same period in 2025 and ongoing earnings of $961
million, or $1.52 per share compared with $737 million or $1.24 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, earnings on equity method investments and
unseasonably warm weather, partially offset by higher financing costs.
“As one of the nation’s largest builders of clean generation and high-voltage
transmission, Xcel Energy continues to make critical investments in the
infrastructure our customers and communities need, while staying focused on
delivering safe, clean, reliable and affordable energy.
We’ve made considerable progress on our priorities this quarter and our updated
five-year investment plan gives us a clear path to extend this growth cycle and
continue to deliver affordable and reliable energy our customers need well into
the next decade,” 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.
US Dial-In: 1-833-461-5787
International Dial-In: +44-117-389-0104
Conference ID: 991 162 104
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.
1
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 and 2027 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.
For more information, contact:
Roopesh Aggarwal, Vice President - (612) 215-4535
Investor Relations
Jessica Noren, Director - Investor (612) 330-5512
Relations
Xcel Energy website address: www.xcelenergy.com (612) 215-5300
This information is not given in connection with any
sale, offer for sale or offer to buy any security.
2
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in millions, except per share data)
Thr… Nine
Mon… Mon…
End… End…
Sep… Sep…
Op… 30 30
re… 2026 2025 2026 2025
──────────────────────────────────────────────────────────────────────────────
El… $ 3,8… $ 3,… $ 9,… $ 9,…
Na… 272 264 1,… 1,…
gas
Ot… 12 13 41 42
To…
op… 4,1… 3,… 11… 11…
re…
Op…
ex…
El…
fu…
and 1,0… 1,… 2,… 3,…
pu…
po…
Co…
of
na…
gas 58 61 671 708
so…
and
tr…
Co…
of
sa… 2 5 7 8
—
ot…
Op…
and 759 692 2,… 2,…
ma…
ex…
Co…
and
de… 125 101 353 299
si…
ma…
ex…
De…
and 791 750 2,… 2,…
am…
Ta…
(o…
th… 178 172 538 514
in…
ta…
Ma…
Wi… 1 287 -18 287
li…
To…
op… 2,9… 3,… 8,… 9,…
ex…
Op… 1,1… 749 2,… 2,…
in…
Ot…
in… 62 46 121 121
net
Ea…
(l…
fr… 77 6 166 -3
eq…
me…
in…
Al…
for
fu…
us… 131 79 328 196
du…
co…
—
eq…
In…
ch…
and
fi…
co…
In…
ch…
—
in… 484 384 1,… 1,…
ot…
fi…
co…
Al…
for
fu…
us… -52 -36 -1… -86
du…
co…
—
de…
To…
in…
ch… 432 348 1,… 979
and
fi…
co…
In…
be… 1,0… 532 2,… 1,…
in…
ta…
In…
tax 69 8 -38 -1…
ex…
(b…
Net $ 960 $ 524 $ 2,… $ 1,…
in…
We…
av…
co…
sh…
ou…
Ba… 629 592 626 584
Di… 632 595 629 587
Ea…
per
av…
co…
sh…
Ba… $ 1.53 $ 0.… $ 3.… $ 2.…
Di… 1.52 0.… 3.… 2.…
3
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.
4
Note 1. Earnings Per Share Summary
Xcel Energy’s third quarter diluted GAAP and ongoing earnings were $1.52 per
share in 2026, compared with GAAP earnings of $0.88 per share and ongoing
earnings of $1.24 in the same period in 2025. The change in ongoing earnings per
share was primarily driven by increased recovery of electric infrastructure
investments, earnings on equity method investments and unseasonably warm
weather, 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:
Diluted
Earnings Three Nine
(Loss) Months Months
Per Ended Ended
Share 2026 Sept. 30 2025 2026 Sept. 30 2025
──────────────────────────────────────────────────────────────────────────────
PSCo $ 0.57 $ 0.08 $ 1.31 $ 0.79
NSP-Min… 0.51 0.53 1.18 1.17
SPS 0.34 0.27 0.67 0.55
NSP-Wis… 0.08 0.07 0.25 0.19
Earnings
from
equity 0.01 0.01 0.03 0.02
method
investm…
— WYCO
Regulat… 1.52 0.96 3.44 2.72
utility…
Xcel
Energy — -0.07 -0.10 -0.24
Inc. and
Other
GAAP
diluted $ 1.52 $ 0.88 $ 3.34 $ 2.47
EPS(a)
Prairie
Island — — 0.04 —
outage
refunds…
Marshall
Wildfire — 0.36 -0.02 0.36
litigat…
Ongoing
diluted $ 1.52 $ 1.24 $ 3.37 $ 2.84
EPS(a)
(a) Amounts may not add due to rounding.
(b) See Note 6.
PSCo
— GAAP earnings increased $0.49 per share and ongoing earnings increased $0.13
per share for the third quarter of 2026. Year-to-date GAAP earnings increased
$0.52 per share and ongoing earnings increased $0.14 per share. The increase in
year-to-date ongoing earnings was driven by higher recovery of electric
infrastructure investments and increased AFUDC, which was partially offset by
increased interest charges and depreciation expenses. The difference between
GAAP and ongoing earnings was driven by the impact of Marshall Wildfire
litigation (See Note 6).
NSP-Minnesota
— GAAP and ongoing earnings decreased $0.02 per share for the third quarter of
2026. Year-to-date GAAP earnings increased $0.01 per share and ongoing earnings
increased $0.05 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 $0.07 per share for the third quarter and
$0.12 per share year-to-date. The year-to-date change was driven by sales
growth, weather, and higher recovery of electric infrastructure investments,
partially offset by increased depreciation expense and interest charges.
NSP-Wisconsin
— GAAP and ongoing earnings increased $0.01 per share for the third quarter and
$0.06 year-to-date. The year-to-date change was driven by higher recovery of
electric and natural gas infrastructure investments, partially offset by
increased O&M expenses, 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.
5
Components significantly contributing to changes in 2026 EPS compared to 2025:
Diluted Earnings Three Months Nine Months
(Loss) Per Share Ended Sept. 30 Ended Sept. 30
──────────────────────────────────────────────────────────────────────────────
GAAP EPS — 2025 $ 0.88 $ 2.47
Components of
change - 2026 vs.
2025
Marshall Wildfire
litigation (See 0.36 0.38
Note
6)
Lower electric
fuel and purchased 0.04 0.35
power
Higher electric 0.32 0.32
revenues
Higher AFUDC 0.11 0.29
equity and debt
Higher earnings
from equity method 0.09 0.21
investments
Higher interest -0.13 -0.35
charges
Common equity -0.10 -0.24
financing
Higher O&M -0.08 -0.09
expenses
Other, net 0.03 —
GAAP EPS — 2026 $ 1.52 $ 3.34
Prairie Island
outage refunds — 0.04
(See Note
6)
Marshall Wildfire
litigation (See — -0.02
Note
6)
Ongoing EPS — $ 1.52 $ 3.37
2026(a)
(a) Amounts may not add due to rounding.
Note 2. Regulated Utility Results
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot
summers or cold winters increase electric and natural gas sales, while mild
weather reduces electric and natural gas sales. The estimated impact of weather
on earnings is based on the number of customers, temperature variances, the
amount of natural gas or electricity historically used per degree of temperature
and excludes any incremental related operating expenses that could result due to
storm activity or vegetation management requirements. As a result, weather
deviations from normal levels can affect Xcel Energy’s financial performance.
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:
Th… Ni…
Mo… Mo…
En… En…
Se… Se…
30 30
20… 20… 20… 20… 20… 20…
vs. vs. vs. vs. vs. vs.
No… No… 20… No… No… 20…
──────────────────────────────────────────────────────────────────────────────
R… $ 0.… $ 0.… $ 0.… $ 0.… $ -0.… $ 0.1…
e…
S… -0… — -0… -0… — -0.…
t…
E… $ 0.… $ 0.… $ 0.… $ 0.… $ -0.… $ 0.0…
t…
F…
n… -0… — -0… -0… — -0.…
g…
D… — 0.… -0… 0.… 0.0… 0.0…
N…
g… $ -0… $ 0.… $ -0… $ -0… $ 0.0… $ -0.…
t…
T… $ 0.… $ 0.… $ 0.… $ -0… $ 0.0… $ -0.…
6
Sales
— Sales growth (decline) for actual and weather-normalized sales volumes in 2026
compared to 2025:
T…
M…
E…
S…
30
P… NS… SPS NS… Xc…
En…
…
… 1… % 6… % 2… % 8… % 1… %
…
… 3… 6… 6… 1… 5…
…
…
… 7… 6… 9… 3… 7…
…
…
…
… -… -… N/A -… -…
…
…
T…
M…
E…
S…
30
P… NS… SPS NS… Xc…
En…
…
… 4… % 1… % 6… % 1… % 3… %
…
… -… 4… 5… -… 2…
…
…
… 1… 3… 5… 0… 3…
…
…
…
… -… -… N/A -… -…
…
…
N…
M…
E…
S…
30
P… NS… SPS NS… Xc…
En…
…
… 3… % 3… % 6… % 2… % 3… %
…
… 0… 3… 6… 1… 3…
…
…
… 1… 3… 6… 1… 3…
…
…
…
… -… -… N/A -… -…
…
…
N…
M…
E…
S…
30
P… NS… SPS NS… Xc…
En…
…
… 1… % 1… % 0… % 1… % 1… %
…
… -… 3… 5… 1… 3…
…
…
… 0… 2… 5… 1… 2…
…
…
…
… -… 0… N/A -… -…
…
…
Weather-normalized electric sales growth (decline) — year-to-date
• Residential sales — Increase is due to both customer growth and higher use per
customer across jurisdictions.
• C&I sales — Increase is due to higher use per customer in SPS (5.6%) and NSP-
Minnesota (2.8%) and customer growth in NSP-Wisconsin (0.9%). 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, partially offset by customer growth
in all jurisdictions.
7
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.
Three Months Nine Months
(Millions of Ended Sept. 30, Ended Sept. 30,
Dollars) 2026 vs. 2025 2026 vs. 2025
──────────────────────────────────────────────────────────────────────────────
Non-fuel riders $ 93 $ 296
Sales and 42 111
demand
Conservation
and demand side
management 29 70
(offset in
expense)
Wholesale 25 69
transmission
Regulatory rate
outcomes (CO, 88 68
MN, ND, SD
and WI)
Estimated
impact of 50 39
weather (net of
sales true-up)
Recovery of
higher (lower)
cost of 11 -158
electric fuel
and purchased
power
PTCs flowed
back to
customers -55 -114
(offset by
ETR)
Wholesale -41 -85
generation
Prairie Island
outage refunds — -38
(See Note
6)
Other, net 8 -5
Total increase $ 250 $ 253
Natural Gas Revenues
— Natural gas revenues vary with changing sales, the cost of natural gas and
regulatory outcomes.
Three Months Nine Months
(Millions of Ended Sept. 30, Ended Sept. 30,
Dollars) 2026 vs. 2025 2026 vs. 2025
──────────────────────────────────────────────────────────────────────────────
Estimated
impact of $ -1 $ -63
weather (net of
decoupling)
Recovery of
lower cost of -7 -42
natural gas
Regulatory rate
outcomes (MN 7 44
and WI)
Other, net 9 13
Total increase $ 8 $ -48
(decrease)
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 $31 million for the third
quarter of 2026 and $272 million year-to-date. The year-to-date change was
primarily due to lower commodity prices, largely in SPS, as well as timing of
fuel recovery mechanisms.
Cost of Natural Gas Sold and Transported —
Expenses incurred for the cost of natural gas sold are impacted by market prices
and seasonality. These costs are generally recovered through various regulatory
recovery mechanisms. As a result, changes in these expenses are largely offset
in operating revenues and have minimal earnings impact.
Natural gas sold and transported decreased $3 million for the third quarter of
2026 and $37 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 $67 million for the third quarter of 2026 and $72
million year-to-date. The year-to-date change was primarily due to increased
generation, wildfire mitigation and gas system costs.
Depreciation and Amortization
— Depreciation and amortization increased $41 million for the third quarter of
2026 and $21 million year-to-date. The year-to-date change was primarily due to
system expansion, partially offset by the recognition of 2025 and 2026
depreciation reductions (nuclear life extensions) in the second quarter of 2026.
Interest Charges
— Interest charges increased $100 million for the third quarter of 2026 and $274
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 $71 million for the third
quarter of 2026 and $169 million year-to-date. The year-to-date change was
primarily due to unrealized gains on investment funds’ interests in energy
technology companies.
8
AFUDC, Equity and Debt
— AFUDC increased $68 million for the third quarter of 2026 and $183 million
year-to-date. The year-to-date change was primarily due to system investment.
Income Taxes
— Effective income tax rate:
T… N…
M… M…
E… E…
S… S…
30 30
2… 2…
2… 2… v… 2… 2… v…
2… 2…
…
… 2… % 2… % — % … % … % — %
…
…
…
…
…
…
…
…
… -… -… 4… … … …
… -… -… -… … … …
… -… -… -… … … …
…
…
…
…
… 3… 3… 0… … … …
…
…
…
…
… 0… -… 1… … … —
…
… 6… % 1… % 5… % … % … % … %
…
…
(a) Wind and Solar PTCs (net of transfer discounts) are generally credited to
customers (reduction to revenue) and do not materially impact earnings.
(b) Regulatory adjustments for income tax primarily relate to the credit of
excess deferred taxes to customers. Income tax benefits associated with the
credit are offset by corresponding revenue reductions.
Note 3. Capital Structure, Liquidity, Financing and Credit Ratings
Xcel Energy’s capital structure:
(Millio… Sept. Percent… Dec. Percent…
of 30, of Total 31, of Total
Dollars) 2026 Capital… 2025 Capital…
──────────────────────────────────────────────────────────────────────────────
Curre…
porti…
of $ 999 1 % $ 501 1 %
long-…
debt
Short… 3,060 5 1,550 3
debt
Long-… 36,539 56 31,832 55
debt
Total 40,598 62 33,883 59
debt
Common 25,501 38 23,609 41
equity
Total $ 66,099 100 % $ 57,492 100 %
capit…
Liquidity
— As of October 27, 2026, Xcel Energy Inc. and its utility subsidiaries had the
following committed credit facilities available to meet liquidity needs:
(M…
of Cre…
Do… Fac… Dra… Ava… Cash Liqu…
──────────────────────────────────────────────────────────────────────────────
Xc…
En… $ 2,0… $ 1,340 $ 660 $ 79 $ 739
In…
PS… 1,2… 48 1,152 645 1,7…
NS… 800 44 756 231 987
SPS 600 — 600 635 1,2…
NS… 150 — 150 135 285
To… $ 4,7… $ 1,432 $ 3,318 $ 1,7… $ 5,0…
Te… $ 1,5… $ 1,500 $ — $ — $ —
Lo…
(a) Expires December 2029.
(b) Includes outstanding commercial paper and letters of credit.
(c) Xcel Energy Inc.’s $1.5 billion term loan matures in January 2027.
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.
9
Credit ratings and long-term outlook assigned to Xcel Energy Inc. and its
utility subsidiaries as of October 28, 2026:
S&P
Moody… Global Fitch
Ratin…
Comp… Credit Rating Outlo… Rating Outlook Rating Outlo…
Type
Xcel
Ener… Unsec… Baa1 Negat… BBB Stable BBB+ Stable
Inc.
NSP-… Secur… Aa3 Stable A Stable A+ Stable
NSP-… Secur… A1 Stable A Stable A+ Stable
PSCo Secur… A1 Negat… A Negati… A+ Stable
SPS Secur… A3 Stable A- Stable A- Stable
Xcel Comme…
Ener… paper P-2 A-2 F2
Inc.
NSP-… Comme… P-1 A-2 F2
paper
NSP-… Comme… P-2 A-2 F2
paper
PSCo Comme… P-2 A-2 F2
paper
SPS Comme… P-2 A-2 F2
paper
Capital Expenditures —
Base capital expenditures for Xcel Energy for 2027 through 2031:
Base
Cap…
For…
By (Mi…
Reg… of
Uti… Dol… 2027 2028 2029 2030 2031 Tot…
──────────────────────────────────────────────────────────────────────────────
SPS $ 6,7… $ 6,3… $ 7,0… $ 2,8… $ 2,8… $ 25,…
NS… 4,6… 4,8… 6,0… 4,9… 4,3… 24,…
PS… 3,8… 2,7… 1,6… 4,7… 3,1… 16,…
NS… 1,1… 860 610 510 430 3,6…
Ot… -130 -170 -80 10 10 -360
To…
ba… $ 16,… $ 14,… $ 15,… $ 13,… $ 10,… $ 70,…
ca…
ex…
(a) Other category includes intercompany transfers for equipment with long lead
times.
Base
Cap…
For…
(Mi…
By of
Fun… Dol… 2027 2028 2029 2030 2031 Tot…
──────────────────────────────────────────────────────────────────────────────
Re… $ 4,8… $ 4,3… $ 6,7… $ 3,8… $ 1,6… $ 21,…
El… 3,5… 3,6… 3,8… 3,7… 3,8… 18,…
Tr…
El… 3,0… 2,8… 1,7… 3,0… 2,9… 13,…
Di…
El… 3,1… 2,5… 1,4… 1,0… 1,0… 9,2…
Ge…
Na… 840 650 650 810 770 3,7…
Gas
Ot… 870 710 750 610 550 3,4…
To…
ba… $ 16,… $ 14,… $ 15,… $ 13,… $ 10,… $ 70,…
ca…
ex…
The plan does not include any potential incremental generation from the current
generation RFPs across jurisdictions, investments to serve future large load
customers or additional transmission investment that may come from future
planning processes including MISO and SPP.
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.
10
Financing for Capital Expenditures through 2031
— 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 2027-2031 (includes the
impact of tax credit transferability):
(Millions of Dollars)
Funding Capital Expenditures
──────────────────────────────────────────────────
Cash from operations(a) $ 35,810
New debt(b) 26,190
Equity issuances(c) 8,000
Base capital expenditures 2027-2031 $ 70,000
Maturing Debt $ 5,630
(a) Net of dividends and pension funding.
(b) Reflects a combination of short and long-term debt; net of refinancing.
(c) Amount could include other financing instruments that receive equity credit
from the credit rating agencies.
2026 Financing Activi
ty
— During 2026, Xcel Energy Inc. and its utility subsidiaries issued the
following long-term debt:
Amount
(in
Issuer Security millions) Tenor Coupon
──────────────────────────────────────────────────────────────────────────────
Xcel Junior 5.75%
Energy subordin… $ 800 30 year fixed-t…
Inc. notes reset
rate
First 3 year & 4.15% &
PSCo mortgage 1,300 10 year 5.05%
bonds
First 10 year & 4.85% &
NSP-Min… mortgage 1,200 30 year 5.55%
bonds
First
NSP-Wis… mortgage 250 15 year 5.48%
bonds
First 10 year & 5.30% &
SPS mortgage 1,200 30 year 5.875%
bonds
First 10 5.35% &
PSCo mortgage 800 year(a)& 6.20%
bonds 30 year
(a) 2024 10 year financing re-opened in 2026. Bonds are due in 2034.
In the third quarter of 2026, 10.5 million shares were issued (net proceeds of
$819 million) in settlements of forward sale agreements or in at-the-market cash
transactions.
During the nine months ended Sept. 30, 2026, Xcel Energy Inc. entered forward
sale agreements totaling 62.1 million shares (minimum expected proceeds of $4.1
billion). As of Sept. 30, 2026, 79.4 million shares remain unsettled on forward
sale agreements (minimum expected proceeds of $5.8 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 — Electric Rate Case Stay-Out Petition — On Oct. 9th, 2026, NSP-
Minnesota filed an Electric Customer Rate Stability Plan with the Minnesota
Public Utilities Commission (MPUC), as an alternative to the planned upcoming
rate case filing.
The terms of the proposed plan are as follows:
• Customer base rate freeze for calendar years 2027 and 2028.
• Accelerated recognition of federal Investment Tax Credit benefits related to
five battery storage projects over two years. This acceleration will act as an
offset to the incremental revenue requirement impact of ongoing necessary
capital improvements.
• Continuation of other true-up and tracker mechanisms as approved in NSP-
Minnesota’s most recent Electric Rate Case.
A MPUC decision on the proposed Rate Stability Plan has been requested by
January 2027. If not approved, NSP-Minnesota expects to file an electric rate
case in early 2027.
11
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 October 2025, NSP-Minnesota filed rebuttal testimony,
updating its total revenue request to $365 million.
In July 2026, the MPUC issued a written order. Terms of the order include:
• Rate increase of approximately $211 million over two years (annual average
increase of 2.9%).
• ROE of 9.60% and equity ratio of 52.5%.
• Continuation of existing true-up mechanisms inclusive of the sales true-up,
coupled with authorization of new tracker mechanisms.
Final rates will take effect in the first quarter of 2027.
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%).
In August 2026, the ALJ issued their report. A MPUC decision is expected in the
fourth quarter of 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. 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-Wisconsin
—
Proposed Sale of Michigan Operations
—
In October 2026, NSP-Wisconsin announced that it has entered into agreements to
sell its approximately $150 million of Michigan electric and gas assets to Upper
Peninsula Power Company and SEMCO ENERGY Gas Company, respectively, contingent
on approvals of the Michigan Public Service Commission, Public Service
Commission of Wisconsin and the Federal Energy Regulatory Commission. NSP-
Wisconsin and the buyers plan to file requests for regulatory approvals by the
end of 2026, with the transactions anticipated to close in 2027. The timing and
amount of the gain for the transactions will be dependent on customary closing
conditions and resolution of the regulatory approval processes.
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
—
Pine Island Data Center
— 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
have been received as part of existing resource acquisition processes. The
remaining resources are expected to be requested in those processes by the
second quarter of 2027.
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.
12
In June 2026, PSCo, CPUC Staff and various other parties filed a comprehensive
non-unanimous settlement agreement. The AARP, City of Boulder and the UCA
opposed the settlement. Other parties either supported portions of the
settlement or did not oppose it.
PSCo received a final decision from the CPUC in September 2026. Terms of the
final decision include:
• Revenue increase (excluding rider roll-ins) of $184 million (5.2% total, or an
annual average of 1.7% since the last rate case), based on a 2025 historical
test year using a 13-month average.
• 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. PSCo also agreed to file a
prudence review related to the outage at the unit (from August 2025 to September
2026) in June 2027.
• Continuation of previously authorized trackers and deferrals.
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 a 13-month
average rate base with forward looking known and measurable adjustments.
• ROE of 9.2% and equity ratio of 54.5%.
The CPUC approved the settlement agreement with minor modifications. Rates were
implemented in October 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 revised load forecast methodology and
authorized the Company to initiate its request for proposals. 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 was issued in the
third quarter of 2026. This RFP is specifically seeking to acquire 500 MW of
additional capacity by 2031 with potential upside for additional capacity as new
large load customers are approved (after consideration of 3,800 MW of approved
acquisitions from the Near-Term Procurement RFP). Bids are due in December 2026,
and a CPUC decision is expected in the second half of 2027.
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. On Oct. 23,
2026, SPS received the Hearing Examiners’ Report, which recommended NMPRC
approval with certain minor modifications. Any exceptions are required to be
filed by Nov. 2, 2026. An NMPRC decision is anticipated in the fourth quarter of
2026, with implementation of rates expected in December 2026.
SPS
—
SPS 2023 Integrated Resource Plan
— In October 2023, SPS filed its Integrated Resource Plan (IRP) with the NMPRC,
which supports projected load growth and increasing reliability requirements,
and secures replacement energy and capacity for retiring resources.
13
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 filed for approval of 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). SPS has received NMPRC approval of the Certificate
of Convenience and Necessity (CCN) filings for the assets. In October 2026, the
PUCT approved the self build portfolio with the exception of the Plant X battery
storage project. The approval includes performance and cost cap guarantees. SPS
will be seeking rehearing on this decision.
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. The portfolio
selection report was publicly filed with the NMPRC in July 2026, with a
preferred portfolio that contains approximately 2,600 MW of nameplate capacity
company owned resources and approximately 1,300 MW of nameplate capacity PPAs.
Project CCNs are expected to be filed in early 2027.
SPS
—
SPS 2026 IRP
— In October 2026, SPS filed its 2026 IRP with the NMPRC, which demonstrates
projected load growth and shows energy and capacity resource portfolio needs
under three different load forecast scenarios. Based on these forecast scenarios
and the progress of existing resource acquisition processes, SPS' initial IRP
modeling identified resource needs of approximately 2,000 MW of incremental
accredited capacity by 2034. Following NMPRC action on the IRP, SPS expects to
issue a competitive all-source solicitation for new generation in mid-2027 with
project selection expected in early 2028.
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 outstanding complaints and claims representing an estimated 141
plaintiff groups (for example, members of the same family and any associated
business, or affiliated corporations). 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. The generally applicable two-year statute of limitations
for property damage in Texas was reached in March 2026.
In total, SPS has settled 358 complaints and claims related to the fire. 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 $410 million of expected loss payments, of which $405
million and $374 million were paid through Sept. 30, 2026 and Dec. 31, 2025,
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. 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. The Texas Attorney General’s claims are in the discovery phase,
which is anticipated to continue into 2027.
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 $65 million of remaining
estimated probable losses for the matter (before available insurance), for a
total estimated loss of $475 million. Additionally, approximately $50 million in
legal costs have been incurred as of Sept. 30, 2026, resulting in total
estimated losses and incurred costs related to this proceeding of $525 million
as of Sept. 30, 2026. An estimated liability of $70 million and $56 million for
estimated losses is presented in other current liabilities as of Sept. 30, 2026
and Dec. 31, 2025, respectively.
14
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 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 $96 million and $195 million,
net of recoveries received are presented in prepayments and other current assets
as of Sept. 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.
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:
Three Nine
(Millions Months Months
of Ended Ended
Dollars) 2026 Sept. 30 2025 2026 Sept. 30 2025
──────────────────────────────────────────────────────────────────────────────
GAAP net $ 960 $ 524 $ 2,102 $ 1,451
income
Prairie
Island — — 38 —
outage
refunds
Marshall
Wildfire 1 287 -18 287
litigati…
Tax — -74 -5 -74
effect
Ongoing $ 961 $ 737 $ 2,117 $ 1,664
earnings
Prairie Island Outage Refunds —
In a September 2024 decision, the MPUC ruled that NSP-Minnesota was imprudent in
the operation of the Prairie Island nuclear plant based on an incident that
resulted in an extended 2023-2024 outage. In May 2026, the MPUC ordered a
disallowance of $41 million for estimated replacement power costs incurred
during the outage. Total non-recurring charges of $38 million were recorded to
electric revenues during the nine months ended Sept. 30, 2026 for incremental
customer refunds, including interest.
15
Marshall Wildfire Litigation
— In September 2025, Xcel Energy and other defendants reached settlement
agreements in principle that resolved all claims relating to the 2021 Marshall
Wildfire. PSCo did not admit any fault, wrongdoing or negligence in connection
with these settlements. During the three months ended Sept. 30, 2025, PSCo
recognized a non-recurring $287 million charge as a result of the settlement.
During the nine months ended Sept. 30, 2026, PSCo recognized $18 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 narrowed range of $4.10 to
$4.16 per share, from the original guidance 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 be flat.
• Capital rider revenue is projected to increase $370 million to $380 million.
The decrease from prior guidance is primarily offset by depreciation and AFUDC
impacts.
• O&M expenses are projected to increase ~5%.
• Depreciation expense is projected to increase approximately $100 million to
$110 million. The decrease from prior guidance is primarily 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 $290 million
to $300 million, net of interest income.
• AFUDC - equity is projected to increase $180 million to $190 million. The
increase from prior guidance is primarily offset by lower revenue.
Xcel Energy 2027 Earnings Guidance —
Xcel Energy’s 2027 ongoing earnings guidance is a range of $4.48 to $4.62 per
share. (a)
Key assumptions as compared with 2026 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 ~5%.
• Weather-normalized retail firm natural gas sales are projected to increase
~1%.
• Capital rider revenue is projected to increase $560 million to $570 million.
• O&M expenses are projected to increase ~4%.
• Depreciation expense is projected to increase approximately $460 million to
$470 million.
• Property taxes are projected to increase $30 million to $40 million.
• Interest expense (net of AFUDC - debt) is projected to increase $320 million
to $330 million, net of interest income.
• AFUDC - equity is projected to increase $250 million to $260 million.
(a) Ongoing earnings is calculated using net income and adjusting for certain
nonrecurring or infrequent items that are, in management’s view, not reflective
of ongoing operations. Ongoing earnings could differ from those prepared in
accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is
unable to quantify the financial impacts of any additional adjustments that may
occur for the year, we are unable to provide a quantitative reconciliation of
the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives
— Xcel Energy expects to deliver an attractive total return to our shareholders
through a combination of earnings growth and dividend yield, based on the
following long-term objectives:
• Deliver long-term annual EPS growth of 6% to 8+%.
• 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.
16
XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (UNAUDITED)
(amounts in millions, except per share data)
Three Months Ended Sept.
30
Operating revenues: 2026 2025
──────────────────────────────────────────────────────────────────────────────
Electric and natural gas $ 4,160 $ 3,902
Other 12 13
Total operating revenues 4,172 3,915
Net income $ 960 $ 524
Weighted average diluted
common shares 632 595
outstanding
Components of EPS —
Diluted
Regulated utility $ 1.52 $ 0.96
Xcel Energy Inc. and — -0.07
other costs
GAAP diluted EPS(a) $ 1.52 $ 0.88
Marshall Wildfire
settlement (See Note — 0.36
6)
Ongoing diluted EPS(a) $ 1.52 $ 1.24
Book value per share $ 40.32 $ 35.59
Cash dividends declared 0.5925 0.57
per common share
Nine Months Ended Sept.
30
Operating revenues: 2026 2025
──────────────────────────────────────────────────────────────────────────────
Electric and natural $ 11,271 $ 11,066
gas
Other 41 42
Total operating 11,312 11,108
revenues
Net income $ 2,102 $ 1,451
Weighted average
diluted common shares 629 587
outstanding
Components of EPS —
Diluted
Regulated utility $ 3.44 $ 2.72
Xcel Energy Inc. and -0.10 -0.24
other costs
GAAP diluted EPS(a) $ 3.34 $ 2.47
Prairie Island outage
refunds (See Note 0.04 —
6)
Marshall Wildfire
settlement (See Note -0.02 0.36
6)
Ongoing diluted EPS(a) $ 3.37 $ 2.84
Book value per share $ 40.56 $ 36.11
Cash dividends declared 1.7775 1.71
per common share
(a) Amounts may not add due to rounding.
17