--- ticker: XEL company: Xcel Energy Inc. filing_type: 10-K year_current: 2026 year_prior: 2025 risks_added: 15 risks_removed: 11 risks_modified: 77 risks_unchanged: 38 source: SEC EDGAR url: https://riskdiff.com/xel/2026-vs-2025/ markdown_url: https://riskdiff.com/xel/2026-vs-2025/index.md generated: 2026-06-01 --- # Xcel Energy Inc.: 10-K Risk Factor Changes 2026 vs 2025 > Source: U.S. Securities and Exchange Commission (EDGAR) > Generated: 2026-06-01 > All data extracted directly from official filings. No hallucinated content. ## Summary | Status | Count | |--------|-------| | New risks added | 15 | | Risks removed | 11 | | Risks modified | 77 | | Unchanged | 38 | --- ## New in Current Filing: Actions of our employees, directors, third-party contractors or suppliers could expose us to reputational risks. We could suffer negative impacts to our reputation as a result of actual or perceived fraud, misconduct, legal or regulatory violations, violations of corporate policies, inappropriate use of social media, or other actions by our employees, directors, third-party contractors or suppliers. Reputational damage could have a material adverse effect and could result in negative customer perception, litigation and increased regulatory oversight. --- ## New in Current Filing: Growth in large load customers, including data centers, may increase customer concentration, capital requirements and revenue variability risks. Additional demand from a limited number of customers may increase our credit risk exposure and require incremental infrastructure investment. If anticipated load growth does not materialize as expected or regulatory cost allocation mechanisms evolve, it could negatively impact our results of operations, financial condition or cash flows. --- ## New in Current Filing: We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows. Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy. We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. --- ## New in Current Filing: We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly. Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. If our regulators do not allow us to recover the costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows. --- ## New in Current Filing: 2025 vs. 2024 2025 vs. 2024 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.5 %1.7 %4.3 %2.1 %2.0 %Electric C&I(0.3)1.6 6.3 0.4 2.4 Total retail electric sales0.3 1.6 5.8 0.9 2.2 Firm natural gas sales0.6 (2.4)N/A2.6 (1.2) --- ## New in Current Filing: Additional Information Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. --- ## New in Current Filing: PSCW decision: Capital investments (1) ROE adjustment (1) O&M expenses (1) Nuclear decommissioning accrual update (a) - Other, net - --- ## New in Current Filing: Pending and Recently Concluded Regulatory Proceedings 2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. 29 29 29 Table of Contents Table of Contents In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026. 2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026. The procedural schedule is as follows: •Intervenor direct testimony: March 20, 2026 •Rebuttal testimony: April 14, 2026 •Evidentiary Hearing: April 28-30, 2026 A SDPUC decision is expected in the first half of 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. --- ## New in Current Filing: Additional Information Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. --- ## New in Current Filing: Supply Chain Xcel Energy's ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability. In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work. Tariffs, Trade Complaints and Federal Actions Several trade cases related to anti-dumping and countervailing duty investigations are ongoing and we continue to monitor the potential impacts of these cases. In 2025, several executive orders have been issued imposing new global and country-specific tariffs on many imports, which may impact our procurement and development activities. Additionally, executive orders and actions from government agencies may impact the permitting of wind and solar facilities and the retirement of coal facilities. Xcel Energy continues to assess the impacts of these tariffs, executive orders, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief, if required, in its jurisdictions. Continued and/or further policy actions or other restrictions, disruptions in imports from key suppliers, or any new trade complaint could impact viability, timelines and costs of various projects and PPAs. --- ## New in Current Filing: Tax Law Changes On July 4, 2025, the President signed into law Public Law No. 119-21 (the "OBBB"). The OBBB modifies certain clean energy tax provisions included in the Inflation Reduction Act. The provisions include: •Eliminating production and investment tax credits for wind and solar facilities placed in service after 2027, for facilities that begin construction after July 4, 2026. •The addition of foreign entity of concern rules that apply to projects commencing construction after 2025. In August 2025, the U.S. Treasury issued further guidance related to the beginning of construction for clean energy projects. In February 2026, the U.S. Treasury and IRS released initial guidance regarding foreign entities of concern. The notice includes interim safe harbor guidance for the purposes of assessing material assistance from a prohibited foreign entity for wind, solar and storage tax credits. Further guidance is expected to be released throughout 2026 related to such rules. Xcel Energy does not expect these provisions to have an impact on our 2026-2030 base capital plan, as steps have been taken to begin construction under the IRS' safe harbor guidance.Excess Liability Insurance CoverageXcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy's employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States.In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million. Xcel Energy has received approval to defer incremental costs in Colorado, Wisconsin and New Mexico and is awaiting approval of a settlement agreement allowing deferral of certain costs in Texas.Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Xcel Energy does not expect these provisions to have an impact on our 2026-2030 base capital plan, as steps have been taken to begin construction under the IRS' safe harbor guidance. --- ## New in Current Filing: Recently Adopted Income Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. Xcel Energy retrospectively implemented this guidance in the year ended Dec. 31, 2025. The adoption impacts were not material. See Note 7 for further information. --- ## New in Current Filing: 4. Regulatory Assets and Liabilities Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2025Dec. 31, 2024 (a)Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$39 $1,121 $39 $1,167 Recoverable deferred taxes on AFUDCPlant lives - 434 - 368 Net AROs1, 12Various - 422 - 387 Depreciation differencesVarious22 320 17 250 Excess deferred taxes - TCJA 7Various11 162 10 184 Grid modernization costsVarious2 67 3 30 Excess liability insurance costsVarious5 64 - 6 Environmental remediation costs1, 12Various9 34 13 39 Prairie Island extended power uprateNine years4 30 4 34 Conservation programs (b)1One to two years18 28 20 30 Nuclear refueling outage costs1One to two years58 20 51 20 Benson biomass PPA termination and asset purchaseThree years10 16 10 26 Deferred natural gas, electric, steam energy/fuel costsOne to two years88 15 99 25 Renewable resources and environmental initiativesOne to two years40 4 34 4 Sales true-up and MN MISO capacity revenueVarious75 2 123 68 Gas pipeline inspection and remediation costsLess than one year31 - 47 9 Other Various117 259 91 202 Total regulatory assets$529 $2,998 $561 $2,849 --- ## New in Current Filing: Minimum Expected Proceeds (millions of dollars) 2025 forward equity agreements (a) Feb. 2026 to Dec. 2028 (b) (c) 2025 collared forward equity agreements (a) (d) (a)Entered under the 2025 ATM prospectus supplement. Entered under the 2025 ATM prospectus supplement. (b)Xcel Energy may settle the agreements at any time until final maturity. Xcel Energy may settle the agreements at any time until final maturity. (c)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy's common stock during the period the agreements are outstanding. Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy's common stock during the period the agreements are outstanding. (d)Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy's common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings. Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy's common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings. If settled in physical shares, stockholders' equity equal to cash proceeds will be recorded at settlement. The 2025 collared forward equity agreements cannot be settled until December 2026, and net cash settlement and net share settlement are generally unavailable. The 2025 forward equity agreements could have been settled at Dec. 31, 2025 with physical delivery of common shares to the banking counterparties in exchange for cash; if Xcel Energy unilaterally elected net cash or net share settlement, these agreements also could have been settled with delivery of cash or shares of common stock to the banking counterparties, as follows:Pro-Forma/Hypothetical TransactionsAgreements EnteredNet Settlement:Physical Share Delivery Proceeds (millions of dollars)Common Shares (in millions)Net Cash (millions of dollars)2025 forward equity agreements0.1$7 $934 Capital Stock - Preferred stock authorized/outstanding:Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2025 and 2024Xcel Energy Inc.7,000,000 $100 - PSCo10,000,000 0.01 - SPS10,000,000 1.00 - Xcel Energy Inc. had the following common stock authorized/outstanding:Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2025Common Stock Outstanding (Shares) as of Dec. 31, 20241,000,000,000 $2.50 623,600,715 574,365,598 Dividend and Other Capital-Related Restrictions - Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.'s utility subsidiaries' dividends are subject to the FERC's jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2025:Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2025NSP-Minnesota47.25 %57.75 %53.16 %NSP-Wisconsin (a)52.50 N/A52.66 SPS (b)45.00 55.00 54.47 (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.(b) Excludes short-term debt.(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$2,185 $19,547 $22,607 NSP-Wisconsin12 3,318 N/ASPS (a)622 8,888 N/A(a)May not pay a dividend that would cause a loss of its investment grade bond rating. The 2025 collared forward equity agreements cannot be settled until December 2026, and net cash settlement and net share settlement are generally unavailable. The 2025 forward equity agreements could have been settled at Dec. 31, 2025 with physical delivery of common shares to the banking counterparties in exchange for cash; if Xcel Energy unilaterally elected net cash or net share settlement, these agreements also could have been settled with delivery of cash or shares of common stock to the banking counterparties, as follows: --- ## New in Current Filing: Pro-Forma/Hypothetical TransactionsAgreements EnteredNet Settlement:Physical Share Delivery Proceeds (millions of dollars)Common Shares (in millions)Net Cash (millions of dollars)2025 forward equity agreements0.1$7 $934 Capital Stock - Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2025 and 2024Xcel Energy Inc.7,000,000 $100 - PSCo10,000,000 0.01 - SPS10,000,000 1.00 - Xcel Energy Inc. had the following common stock authorized/outstanding: --- ## No Match in Current: Oversight of Risk and Related Processes *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors' committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors. Xcel Energy maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our Code of Conduct and compliance policies, operation of formal risk management structures and overall business management. Xcel Energy further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal. Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing Xcel Energy's strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals. Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management's key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental, safety and security risks. The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors' governance of Xcel Energy. The Board of Directors assigns oversight of critical risks to each of its four committees to confirm these risks are well understood and given appropriate focus. The Audit Committee is responsible for reviewing the adequacy of the committees' risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate.Emerging risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy's future plans and initiatives are reviewed.Risks Associated with Our BusinessOperational RisksOur natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential reputational impact.Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to:•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. •Failures in the availability, acquisition or transportation of fuel or other supplies. •Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns•Performance below expected or contracted levels of output or efficiency.•Availability of replacement or new equipment. •Availability of adequate water resources and ability to satisfy water intake and discharge requirements. •Inability to identify, manage properly or mitigate equipment defects. •Use of new or unproven technology. •Inability to use information effectively given the rapidly increasing volume of data.•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes. •Increased costs due to aging infrastructure. The Audit Committee is responsible for reviewing the adequacy of the committees' risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate. Emerging risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy's future plans and initiatives are reviewed. --- ## No Match in Current: Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation. *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. 17 17 17 Table of Contents Table of Contents Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs, and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota's nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs, and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. --- ## No Match in Current: Operations could be impacted by war, terrorism or other events. *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption. In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows. --- ## No Match in Current: Increased risks of regulatory penalties could negatively impact our business. *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. --- ## No Match in Current: 2024 vs. 2023 *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* 2024 vs. 2023 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(0.1)%0.7 %(1.5)%(1.8)%(0.1)%Electric C&I(2.0)(1.4)9.0 (1.8)1.5 Total retail electric sales(1.4)(0.7)7.1 (1.8)1.0 Firm natural gas sales(1.7) - N/A(3.1)(0.7)Annual weather-normalized and leap year adjusted electric sales growth (decline)•NSP-Minnesota - Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector.•PSCo - Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining. •SPS - Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining. •NSP-Wisconsin - Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.Annual weather-normalized and leap year adjusted natural gas sales growth (decline)•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions. Electric RevenuesElectric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of electric fuel and purchase power(479)PTCs flowed back to customers (offset by lower ETR)(302)Wholesale generation revenues(96)Sherco Unit 3 2011 outage refunds(47)Regulatory rate outcomes (MN, CO, TX, and NM)372 Non-fuel riders169 Conservation and demand side management (offset in expense)102 Estimated impact of weather (net of sales true-up)24 Other, net(42)Total decrease$(299) 2024 vs. 2023 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(0.1)%0.7 %(1.5)%(1.8)%(0.1)%Electric C&I(2.0)(1.4)9.0 (1.8)1.5 Total retail electric sales(1.4)(0.7)7.1 (1.8)1.0 Firm natural gas sales(1.7) - N/A(3.1)(0.7) --- ## No Match in Current: Nuclear Power Operations *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use. NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs. Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable. High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site. Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2. In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050. In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. --- ## No Match in Current: Additional Information *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. --- ## No Match in Current: Purchased Power and Transmission Service Providers *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs. Purchased Power - PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo's long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost. Purchased Transmission Services - In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers. --- ## No Match in Current: Commitments and Contingencies - Wildfires - Refer to Note 12 to the consolidated financial statements *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* Critical Audit Matter Description As a result of wildfires that have occurred in the Company's service territory in Colorado and Texas, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with the 2021 Marshall Wildfire and the 2024 Smokehouse Creek Fire Complex (the "Wildfires"). In evaluating this exposure, the Company is required to determine whether the likelihood of loss for each of the Wildfires is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the Wildfires, investigations, and discovery associated with lawsuits. A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts. A current asset for claim amounts that are recoverable from insurance related to a loss contingency is recorded when it is probable the claim will be recovered. We identified contingencies from the Wildfires and the related disclosures as a critical audit matter due to the significant judgments made by management to determine the probability of loss and estimate the probable losses and insurance recoveries. Auditing the reasonableness of management's judgments, estimates and disclosures related to the Wildfires required a high degree of auditor judgment and increased extent of audit effort. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to management's judgments regarding the probability of loss, estimated losses and insurance recoveries, and related disclosures for contingencies related to the Wildfires included the following, among others: •We tested the effectiveness of controls over (1) the Company's determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss and probable insurance recoveries; and (3) the disclosures related to the Wildfires. •We evaluated management's judgments related to whether a loss was probable or reasonably possible from the Wildfires by inquiring of management and the Company's external and internal legal counsel. We also evaluated the potential impact of information gained through the Company and third parties' investigations into the cause of the Wildfires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management's assertions. •We evaluated management's methodologies for assessing estimates of loss and recording a probable loss through inquiries with management and external and internal legal counsel and we tested the significant assumptions, including payments to settle claims, used in the estimates of probable loss. •We read legal letters from the Company's external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures. •We evaluated management's judgments related to whether certain insurance recoveries were probable of collection by inquiring of management and the Company's internal legal counsel regarding the amounts of insurance recoveries recorded or disclosed. We obtained and inspected relevant insurance policies to evaluate coverages as well as communication between the Company and insurers. •We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures. /s/ DELOITTE & TOUCHE LLPMinneapolis, MinnesotaFebruary 27, 2025We have served as the Company's auditor since 2002. /s/ DELOITTE & TOUCHE LLP 47 47 47 Table of Contents Table of Contents --- ## No Match in Current: Recently Adopted *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* Segment Reporting - In November 2023, the FASB issued ASU 2023-07 - Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material. See Note 14 for further information. --- ## No Match in Current: 6. Revenues *This section from the 2025 filing does not have a high-confidence textual match in 2026. It may have been removed, merged, or substantially reworded.* Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy's operating revenues consisted of the following: Year Ended Dec. 31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 - 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 - - 645 Transmission648 - - 648 Other64 175 - 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 - 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 - - 815 Transmission649 - - 649 Other63 156 - 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 - 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 - - 1,354 Transmission675 - - 675 Other97 178 - 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 --- ## Modified: Excess Liability Insurance Coverage **Key changes:** - Reworded sentence: "In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million." **Prior (2025):** Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy's employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states. **Current (2026):** Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy's employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million. Xcel Energy has received approval to defer incremental costs in Colorado, Wisconsin and New Mexico and is awaiting approval of a settlement agreement allowing deferral of certain costs in Texas. --- ## Modified: Operations could be impacted by war, terrorism or other events. **Key changes:** - Removed sentence: "Health epidemics impact countries, communities, supply chains and markets." - Removed sentence: "Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy." - Removed sentence: "We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations." - Removed sentence: "Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak." - Removed sentence: "19 19 19 Table of Contents Table of Contents Operations could be impacted by war, terrorism or other events." **Prior (2025):** Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy. We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. 19 19 19 Table of Contents Table of Contents Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. **Current (2026):** Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. 19 19 19 Table of Contents Table of Contents We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Advancements in artificial intelligence and large language models may increase cybersecurity threats and operational risks. Threat actors may use artificial intelligence to enhance their attacks, increasing the frequency, sophistication and potential impact of cyber incidents affecting our IT and OT environment.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Advancements in artificial intelligence and large language models may increase cybersecurity threats and operational risks. Threat actors may use artificial intelligence to enhance their attacks, increasing the frequency, sophistication and potential impact of cyber incidents affecting our IT and OT environment. We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption. In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows. --- ## Modified: Recovery Mechanisms **Key changes:** - Reworded sentence: "MechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.Clean Energy Plan RevenueRecovers projects approved through the Clean Energy Plan to a maximum of 1.25% of the customer's bill.DSM Cost AdjustmentRecovers electric and gas DSM and CHP, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel, purchased energy costs and certain owned renewable generating assets." - Reworded sentence: "PTCs earned for owned wind and solar generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC." - Reworded sentence: "Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Wildfire Mitigation AdjustmentRecovers actual 2025-2027 costs associated with wildfire mitigation." **Prior (2025):** MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. **Current (2026):** MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. --- ## Modified: Station, Location and Unit at Dec. 31, 2025 **Key changes:** - Reworded sentence: "MW (a) (b) (b) (a)Summer 2025 net dependable capacity." - Reworded sentence: "(b)Net maximum capacity is attainable only when conditions are sufficiently available." - Reworded sentence: "31, 2025 SPS' wind facilities had a weighted-average capacity factor of 47%." - Reworded sentence: "31, 2025: Conductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPSTransmission500 KV2,921 - - - 345 KV13,394 3,019 8,233 11,668 230 KV2,299 - 12,393 9,863 161 KV610 1,816 - - 138 KV - - 92 - 115 KV8,137 1,860 5,004 15,044 Less than 115 KV6,569 5,666 1,717 4,546 Total Transmission33,930 12,361 27,439 41,121 DistributionLess than 115 KV87,271 28,582 84,079 25,261 Total121,201 40,943 111,518 66,382 Electric utility transmission and distribution substations at Dec." - Reworded sentence: "The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 37 companies at year-end and is a broad measure of industry performance.Comparison of Five Year Cumulative Total Return** $100 invested on Dec." **Prior (2025):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota's wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo's wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 **Current (2026):** MW (a) (b) (c) (d) (e) (e) Border-Rolette County, ND, 75 Units (f) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (e) (e) (e) (e) (e) (e) Pleasant Valley-Mower County, MN, 100 Units (f) (e) (e) (e) (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Four units were retired in 2025. (e)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 44%. For solar projects placed in service in 2025, factors will be available after a full year of operations. (f)Repowered in 2025. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 (a)Summer 2025 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units.PSCoStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 (e)Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Solar:Rocky Mountain Solar-Keenesburg, CO, 87 unitsSolar2025325 (f)Total6,528 (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Pawnee coal plant was retired in 2025 and completed conversion to natural gas in 2026.(f)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 41%. For solar projects placed in service in 2025, factors will be available after a full year of operations. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 --- ## Modified: Station, Location and Unit at Dec. 31, 2025 **Key changes:** - Reworded sentence: "MW (a) (b) (c) (c) (a)Summer 2025 net dependable capacity." - Reworded sentence: "(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units." - Reworded sentence: "31, 2025FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 (e)Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St." **Prior (2025):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota's wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo's wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 **Current (2026):** MW (a) (b) (c) (d) (e) (e) Border-Rolette County, ND, 75 Units (f) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (e) (e) (e) (e) (e) (e) Pleasant Valley-Mower County, MN, 100 Units (f) (e) (e) (e) (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Four units were retired in 2025. (e)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 44%. For solar projects placed in service in 2025, factors will be available after a full year of operations. (f)Repowered in 2025. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 (a)Summer 2025 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units.PSCoStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 (e)Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Solar:Rocky Mountain Solar-Keenesburg, CO, 87 unitsSolar2025325 (f)Total6,528 (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Pawnee coal plant was retired in 2025 and completed conversion to natural gas in 2026.(f)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 41%. For solar projects placed in service in 2025, factors will be available after a full year of operations. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 --- ## Modified: Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers. **Key changes:** - Reworded sentence: "17 17 17 Table of Contents Table of Contents The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment." - Reworded sentence: "Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery." - Reworded sentence: "Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers.Regulators may challenge rate increases due to increased customer affordability pressures." - Added sentence: "Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations." - Added sentence: "Should the counterparties fail to perform, we may be forced to enter into alternative arrangements." **Prior (2025):** We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota's nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows. **Current (2026):** We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers. 17 17 17 Table of Contents Table of Contents The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers.Regulators may challenge rate increases due to increased customer affordability pressures. Public policy developments, including legislative actions and electoral changes at the state level, may affect recovery mechanisms or allowed returns and may limit recovery timing or cost allocation, negatively impacting our results of operations, financial condition or cash flows.Growth in large load customers, including data centers, may increase customer concentration, capital requirements and revenue variability risks.Additional demand from a limited number of customers may increase our credit risk exposure and require incremental infrastructure investment. If anticipated load growth does not materialize as expected or regulatory cost allocation mechanisms evolve, it could negatively impact our results of operations, financial condition or cash flows.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota's nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract. The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers.Regulators may challenge rate increases due to increased customer affordability pressures. Public policy developments, including legislative actions and electoral changes at the state level, may affect recovery mechanisms or allowed returns and may limit recovery timing or cost allocation, negatively impacting our results of operations, financial condition or cash flows.Growth in large load customers, including data centers, may increase customer concentration, capital requirements and revenue variability risks.Additional demand from a limited number of customers may increase our credit risk exposure and require incremental infrastructure investment. If anticipated load growth does not materialize as expected or regulatory cost allocation mechanisms evolve, it could negatively impact our results of operations, financial condition or cash flows.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility's costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Regulators may challenge rate increases due to increased customer affordability pressures. Public policy developments, including legislative actions and electoral changes at the state level, may affect recovery mechanisms or allowed returns and may limit recovery timing or cost allocation, negatively impacting our results of operations, financial condition or cash flows. --- ## Modified: We are subject to credit risks. **Key changes:** - Reworded sentence: "Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations." - Reworded sentence: "If the security were not replaced, the party could be in default under the contract." - Reworded sentence: "Operations could be impacted by war, terrorism or other events." - Reworded sentence: "If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected." **Prior (2025):** Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. 18 18 18 Table of Contents Table of Contents Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary's ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.Macroeconomic RisksEconomic conditions impact our business.Xcel Energy's operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers' ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary's ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract. **Current (2026):** Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract. 18 18 18 Table of Contents Table of Contents Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary's ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.Macroeconomic RisksEconomic conditions impact our business.Xcel Energy's operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers' ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary's ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources. --- ## Modified: Nuclear Decommissioning **Key changes:** - Reworded sentence: "A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities." - Reworded sentence: "The amounts recorded for AROs related to future nuclear decommissioning were $2.6 billion in 2025 and $2.5 billion in 2024." - Reworded sentence: "In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed and was approved by the MPUC in May 2025." - Reworded sentence: "38 38 38 Table of Contents Table of Contents Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities." - Reworded sentence: "31, 2025.See Note 12 to the consolidated financial statements for further information.Loss Contingencies - WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty." **Prior (2025):** Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. 37 37 37 Table of Contents Table of Contents A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.5 billion in 2024 and $2.1 billion in 2023. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed. The following assumptions have a significant effect on the estimated nuclear obligation:Timing - Decommissioning cost estimates are impacted by each facility's retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit's operating license with the NRC (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively). In December 2024, the operating license for Xcel Energy's Monticello Nuclear Generating Plant in Monticello, MN was renewed. The approval allows the plant to operate an additional 20 years, through 2050. As of Dec. 31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040. In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received.The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors.Discount Rates - Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2024.See Note 12 to the consolidated financial statements for further information.Loss Contingencies - WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 12 accompanying the consolidated financial statements for additional information. Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.5 billion in 2024 and $2.1 billion in 2023. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed. The following assumptions have a significant effect on the estimated nuclear obligation:Timing - Decommissioning cost estimates are impacted by each facility's retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit's operating license with the NRC (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively). In December 2024, the operating license for Xcel Energy's Monticello Nuclear Generating Plant in Monticello, MN was renewed. The approval allows the plant to operate an additional 20 years, through 2050. As of Dec. 31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040. In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received.The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors.Discount Rates - Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.5 billion in 2024 and $2.1 billion in 2023. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed. The following assumptions have a significant effect on the estimated nuclear obligation: Timing - Decommissioning cost estimates are impacted by each facility's retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit's operating license with the NRC (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively). In December 2024, the operating license for Xcel Energy's Monticello Nuclear Generating Plant in Monticello, MN was renewed. The approval allows the plant to operate an additional 20 years, through 2050. As of Dec. 31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040. In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received. The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101. Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors. Discount Rates - Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2024.See Note 12 to the consolidated financial statements for further information.Loss Contingencies - WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 12 accompanying the consolidated financial statements for additional information. Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time. Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially. However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates. NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2024. See Note 12 to the consolidated financial statements for further information. **Current (2026):** Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.6 billion in 2025 and $2.5 billion in 2024. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed and was approved by the MPUC in May 2025. The following assumptions have a significant effect on the estimated nuclear obligation: Timing - Decommissioning cost estimates are impacted by each facility's retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit's operating license with the NRC. NSP-Minnesota's current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. During 2025, the Commission approved extended lives for Prairie Island Unit 1 and Unit 2 and Monticello (2053, 2054, and 2050, respectively) in the Upper Midwest Resource Plan. A request to update authorized retirement dates and related decommissioning estimates to incorporate the extended lives are pending with the Commission. These will be incorporated in decommissioning estimates once additional approvals have been received. The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101. Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. 38 38 38 Table of Contents Table of Contents Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used escalation rates of 3.30% and 4.50%, for non-labor and labor expenses respectively, in calculating the ARO for nuclear decommissioning of its nuclear facilities.Discount Rates - Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2025.See Note 12 to the consolidated financial statements for further information.Loss Contingencies - WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigation, legal proceedings, mediations and settlements are considered. See Note 12 accompanying the consolidated financial statements for additional information. Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2025:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(10)$(15)$(3)$(1)$(29)NSP-Minnesota (b)1 (2) - (4)(5)PSCo (a)(1) - - - (1)$(10)$(17)$(3)$(5)$(35)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $10 $10 $ - $20 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods. Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used escalation rates of 3.30% and 4.50%, for non-labor and labor expenses respectively, in calculating the ARO for nuclear decommissioning of its nuclear facilities.Discount Rates - Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2025.See Note 12 to the consolidated financial statements for further information.Loss Contingencies - WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigation, legal proceedings, mediations and settlements are considered. See Note 12 accompanying the consolidated financial statements for additional information. Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used escalation rates of 3.30% and 4.50%, for non-labor and labor expenses respectively, in calculating the ARO for nuclear decommissioning of its nuclear facilities. Discount Rates - Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time. Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially. However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates. NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2025. See Note 12 to the consolidated financial statements for further information. --- ## Modified: Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives **Key changes:** - Reworded sentence: "Xcel Energy 2026 Earnings Guidance - Xcel Energy's 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share." - Reworded sentence: "•Capital rider revenue is projected to increase $535 million to $545 million." - Reworded sentence: "•Depreciation expense is projected to increase approximately $350 million to $360 million." - Reworded sentence: "Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives: • Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share." - Reworded sentence: "• Target a dividend payout ratio of 45% to 55%." **Prior (2025):** Xcel Energy 2025 Earnings Guidance - Xcel Energy's 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a) Key assumptions as compared with 2024 actual levels unless noted: •Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans. •Normal weather patterns for the year. •Weather-normalized retail electric sales are projected to increase ~3%. •Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs). •O&M expenses are projected to increase ~3%. •Depreciation expense is projected to increase approximately $210 million to $220 million. •Property taxes are projected to increase $55 million to $65 million. •Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income. •AFUDC - equity is projected to increase $110 million to $120 million. (a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management's view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS. Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:• Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).• Deliver annual dividend increases of 4% to 6%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives: • Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share). • Deliver annual dividend increases of 4% to 6%. • Target a dividend payout ratio of 50% to 60%. • Maintain senior secured debt credit ratings in the A range. ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference. ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Item 15-1 for an index of financial statements included herein. See Note 15 to the consolidated financial statements for further information. 43 43 43 Table of Contents Table of Contents **Current (2026):** Xcel Energy 2026 Earnings Guidance - Xcel Energy's 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. (a) Key assumptions as compared with 2025 actual levels unless noted: •Constructive outcomes in all pending rate case and regulatory proceedings. •Normal weather patterns for the year. •Weather-normalized retail electric sales are projected to increase ~3%. •Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $535 million to $545 million. •O&M expenses are projected to increase ~3%. •Depreciation expense is projected to increase approximately $350 million to $360 million. •Property taxes are projected to increase $30 million to $40 million. •Interest expense (net of AFUDC - debt) is projected to increase $300 million to $310 million, net of interest income. •AFUDC - equity is projected to increase $140 million to $150 million. (a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management's view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS. Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives: • Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share. • 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. ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference. ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Item 15-1 for an index of financial statements included herein. See Note 15 to the consolidated financial statements for further information. 43 43 43 Table of Contents Table of Contents --- ## Modified: Our operations use third-party contractors in addition to employees to perform periodic and ongoing work. **Key changes:** - Removed sentence: "Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance." - Added sentence: "Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution." **Prior (2025):** We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. **Current (2026):** We rely on third-party contractors to perform operations, maintenance and construction work. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution. --- ## Modified: Our utility operations, resource adequacy and system reliability are subject to long-term planning and project risks. **Key changes:** - Reworded sentence: "Our ability to reliably serve customer demand depends on the availability of sufficient generation and capacity resources." - Reworded sentence: "These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology, equipment availability and public policy." - Added sentence: "Enterprise level financial and customer billing technology systems may be unable to support the increasing customer complexity." - Reworded sentence: "Our utilities have significant risks associated with wildfires.In recent years, wildfires have impacted the utility industry." - Added sentence: "Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules." **Prior (2025):** Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy's long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines. In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. Our utilities have physical and financial risks associated with wildfires.In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Wildfires could jeopardize Xcel Energy's electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. **Current (2026):** Our ability to reliably serve customer demand depends on the availability of sufficient generation and capacity resources. Changes in load growth, resource retirements, accreditation of resources, generation performance, extreme weather events, or delays in development or delivery of new resources, including the necessary transmission infrastructure, could affect resource adequacy and system reliability. 15 15 15 Table of Contents Table of Contents Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology, equipment availability and public policy. Xcel Energy's long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., the addition of large loads, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency or other reductions in expected sales growth could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. Additionally, increasing uncertainty surrounding federal policy to renewable deployment could negatively impact wind, solar and storage development. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Enterprise level financial and customer billing technology systems may be unable to support the increasing customer complexity. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. Our utilities have significant risks associated with wildfires.In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in availability of vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other environmental factors have increased both the frequency and duration of fire weather conditions and the potential impact of an event. The expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Also, wildfires could jeopardize Xcel Energy's electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Our current wildfire mitigation initiatives may not be effective in preventing or reducing ignitions and wildfire-related losses.Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, damage amounts could exceed our coverage (as experienced with the Marshall Wildfire settlement in 2025) and negatively impact our results of operations, financial condition or cash flows. Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology, equipment availability and public policy. Xcel Energy's long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., the addition of large loads, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency or other reductions in expected sales growth could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. Additionally, increasing uncertainty surrounding federal policy to renewable deployment could negatively impact wind, solar and storage development. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Enterprise level financial and customer billing technology systems may be unable to support the increasing customer complexity. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows. Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology, equipment availability and public policy. Xcel Energy's long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines. In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., the addition of large loads, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency or other reductions in expected sales growth could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. Additionally, increasing uncertainty surrounding federal policy to renewable deployment could negatively impact wind, solar and storage development. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Enterprise level financial and customer billing technology systems may be unable to support the increasing customer complexity. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. --- ## Modified: Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $10 $10 $ - $20 **Key changes:** - Reworded sentence: "39 39 39 Table of Contents Table of Contents Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec." - Reworded sentence: "Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided." **Prior (2025):** NSP-Minnesota (b) (a)Prices actively quoted or based on actively quoted prices. (b)Prices based on models and other valuation methods. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31: (Millions of Dollars)20242023Fair value of commodity trading net contracts outstanding at Jan. 1$1 $(10)Contracts realized or settled during the period - (2)Commodity trading contract additions and changes during the period(3)13 Fair value of commodity trading net contracts outstanding at Dec. 31$(2)$1 A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2024 and $4 million at Dec. 31, 2023. The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2024$ - $ - $1 $ - 2023 - - 1 - Nuclear Fuel Supply - NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows: **Current (2026):** NSP-Minnesota (b) (a)Prices actively quoted or based on actively quoted prices. (b)Prices based on models and other valuation methods. 39 39 39 Table of Contents Table of Contents Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20252024Fair value of commodity trading net contracts outstanding at Jan. 1$(2)$1 Contracts realized or settled during the period(1) - Commodity trading contract additions and changes during the period(12)(3)Fair value of commodity trading net contracts outstanding at Dec. 31$(15)$(2)A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2025 and Dec. 31, 2024.The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2025$ - $ - $1 $ - 2024 - - 1 - Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $17 million and $7 million in 2025 and 2024, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Xcel Energy's subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support.Xcel Energy is also subject to credit risk for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.At Dec. 31, 2025, a 10% increase or decrease in commodity prices would have resulted in an increase or decrease in credit exposure of $27 million. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $25 million.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2024$4,641 Components of change - 2025 vs. 2024Higher net income82 Non-cash transactions121 Changes in deferred taxes189 Changes in working capital (304)Changes in net regulatory and other assets and liabilities(646)Cash provided by operating activities - 2025$4,083 Net cash provided by operating activities decreased by $558 million for 2025 as compared to 2024. The decrease was largely due to the payment of the Marshall Wildfire settlement and timing of regulatory recovery, including deferred fuel costs. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20252024Fair value of commodity trading net contracts outstanding at Jan. 1$(2)$1 Contracts realized or settled during the period(1) - Commodity trading contract additions and changes during the period(12)(3)Fair value of commodity trading net contracts outstanding at Dec. 31$(15)$(2)A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2025 and Dec. 31, 2024.The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2025$ - $ - $1 $ - 2024 - - 1 - Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $17 million and $7 million in 2025 and 2024, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31: (Millions of Dollars)20252024Fair value of commodity trading net contracts outstanding at Jan. 1$(2)$1 Contracts realized or settled during the period(1) - Commodity trading contract additions and changes during the period(12)(3)Fair value of commodity trading net contracts outstanding at Dec. 31$(15)$(2) A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2025 and Dec. 31, 2024. The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows: --- ## Modified: Dec. 31, 2024 (a) **Key changes:** - Reworded sentence: "Excess deferred taxes - TCJA Nine years Nine Conservation programs (b) One to two years One two One to two years One two Three years Three One to two years One two One to two years One two Less than one year one Other (a)Prior period amounts have been reclassified to conform with current year presentation." - Reworded sentence: "31, 2024Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (a)7Various$7 $2,758 $7 $2,888 Plant removal costs1, 12Various - 2,336 - 2,208 Net AROs (b)Various - 354 - 161 Renewable resources and environmental initiativesVarious16 319 16 232 Effects of regulation on employee benefit costs (c)11Various - 261 - 259 ITC deferrals1Various - 64 - 70 IRA deferralOne to two years19 19 3 37 Deferred natural gas, electric, steam energy/fuel costsOne to two years296 13 480 12 Contract valuation adjustments (d)1, 10Less than one year144 - 89 - Conservation programs (e)1Less than one year39 - 52 - Other Various193 153 205 143 Total regulatory liabilities$714 $6,277 $852 $6,010 Deferred income tax adjustments and TCJA refunds (a) Net AROs (b) Effects of regulation on employee benefit costs (c) ITC deferrals One to two years One two One to two years One two Contract valuation adjustments (d) Less than one year one Conservation programs (e) Less than one year one (a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA." - Reworded sentence: "(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments." - Removed sentence: "(c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments." - Removed sentence: "Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments." **Prior (2025):** Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2024Dec. 31, 2023Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$39 $1,167 $27 $1,106 Net AROs1, 12Various - 387 - 316 Recoverable deferred taxes on AFUDCPlant lives - 368 - 332 Depreciation differencesVarious17 250 17 189 Excess deferred taxes - TCJA 7Various10 184 10 198 MISO capacity revenue trackerOne to two years63 45 36 26 Environmental remediation costs1, 12Various13 39 15 94 Prairie Island extended power uprate10 years4 34 4 38 Conservation programs (a)1One to two years20 30 19 54 Purchased power contract costsTerm of related contract5 28 4 40 Benson biomass PPA termination and asset purchaseFour years10 26 10 36 Deferred natural gas, electric, steam energy/fuel costsOne to two years99 25 239 80 Sales true-up and revenue decouplingVarious60 23 7 33 Nuclear refueling outage costs1One to two years51 20 43 19 Gas pipeline inspection and remediation costsOne to two years47 9 40 25 Renewable resources and environmental initiativesOne to two years34 4 38 5 Other Various89 210 102 207 Total regulatory assets$561 $2,849 $611 $2,798 Excess deferred taxes - TCJA One to two years One two Conservation programs (a) One to two years One two Four years Four One to two years One two One to two years One two One to two years One two One to two years One two Other (a)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2024Dec. 31, 2023Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (a)7Various$7 $2,888 $7 $3,015 Plant removal costs1, 12Various - 2,208 - 1,984 Effects of regulation on employee benefit costs (b)11Various - 259 - 253 Renewable resources and environmental initiativesVarious16 232 9 188 Net AROs (c)Various - 161 - 90 ITC deferrals1Various - 70 1 60 IRA deferralOne to three years3 37 - - Deferred natural gas, electric, steam energy/fuel costsOne to two years480 12 220 - Contract valuation adjustments (d)1, 10Less than one year89 - 56 - Conservation programs (e)1Less than one year52 - 47 - Other Various205 143 188 237 Total regulatory liabilities (f)$852 $6,010 $528 $5,827 Deferred income tax adjustments and TCJA refunds (a) Effects of regulation on employee benefit costs (b) Net AROs (c) ITC deferrals One to three years One three One to two years One two Contract valuation adjustments (d) Less than one year one Conservation programs (e) Less than one year one Total regulatory liabilities (f) (a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.. (f)Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities. Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities. Xcel Energy's regulatory assets not earning a return include past expenditures of $892 million and $1,085 million at Dec. 31, 2024 and 2023 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return. 58 58 58 Table of Contents Table of Contents 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31202420232022Borrowing limit$3,550 $3,550 $3,550 $3,550 Amount outstanding at period end695 695 785 813 Average amount outstanding133 508 491 552 Maximum amount outstanding695 1,314 1,241 1,357 Weighted average interest rate, computed on a daily basis4.77 %5.47 %5.12 %1.47 %Weighted average interest rate at period end4.64 4.64 5.52 4.66 Bilateral Credit Agreement - In April 2024, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027.Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20242023Xcel Energy Inc. (d)59.8 %59.8 %$350 2 NSP-Minnesota47.0 47.7 150 2 NSP-Wisconsin47.1 48.2 N/A1 SPS46.6 46.1 50 2 PSCo45.2 44.8 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2024, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2024:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $235 $1,265 PSCo700 115 585 NSP-Minnesota700 207 493 SPS500 145 355 NSP-Wisconsin150 35 115 Total$3,550 $737 $2,813 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31202420232022Borrowing limit$3,550 $3,550 $3,550 $3,550 Amount outstanding at period end695 695 785 813 Average amount outstanding133 508 491 552 Maximum amount outstanding695 1,314 1,241 1,357 Weighted average interest rate, computed on a daily basis4.77 %5.47 %5.12 %1.47 %Weighted average interest rate at period end4.64 4.64 5.52 4.66 Bilateral Credit Agreement - In April 2024, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. **Current (2026):** Excess deferred taxes - TCJA Nine years Nine Conservation programs (b) One to two years One two One to two years One two Three years Three One to two years One two One to two years One two Less than one year one Other (a)Prior period amounts have been reclassified to conform with current year presentation. Prior period amounts have been reclassified to conform with current year presentation. (b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2025Dec. 31, 2024Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (a)7Various$7 $2,758 $7 $2,888 Plant removal costs1, 12Various - 2,336 - 2,208 Net AROs (b)Various - 354 - 161 Renewable resources and environmental initiativesVarious16 319 16 232 Effects of regulation on employee benefit costs (c)11Various - 261 - 259 ITC deferrals1Various - 64 - 70 IRA deferralOne to two years19 19 3 37 Deferred natural gas, electric, steam energy/fuel costsOne to two years296 13 480 12 Contract valuation adjustments (d)1, 10Less than one year144 - 89 - Conservation programs (e)1Less than one year39 - 52 - Other Various193 153 205 143 Total regulatory liabilities$714 $6,277 $852 $6,010 Deferred income tax adjustments and TCJA refunds (a) Net AROs (b) Effects of regulation on employee benefit costs (c) ITC deferrals One to two years One two One to two years One two Contract valuation adjustments (d) Less than one year one Conservation programs (e) Less than one year one (a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (c)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Xcel Energy's regulatory assets not earning a return include past expenditures of $799 million and $892 million at Dec. 31, 2025 and 2024 respectively, which predominately relate to certain prepaid pension amounts, purchased natural gas and electric energy costs, deferred excess liability insurance costs, sales true-up and revenue decoupling and other renewable resources/environmental initiatives. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e., deferrals for which cash has not been disbursed) do not earn a return. 57 57 57 Table of Contents Table of Contents 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2025Year Ended Dec. 31202520242023Borrowing limit$4,750 $4,750 $3,550 $3,550 Amount outstanding at period end1,550 1,550 695 785 Average amount outstanding1,622 1,026 508 491 Maximum amount outstanding2,965 2,965 1,314 1,241 Weighted average interest rate, computed on a daily basis4.14 %4.41 %5.47 %5.12 %Weighted average interest rate at period end3.95 3.95 4.64 5.52 Bilateral Credit Agreement - In April 2025, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2025, NSP-Minnesota had $69 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2025 and 2024, there were $92 million and $42 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $4.75 billion. The amended credit agreements mature in December 2029.Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20252024Xcel Energy Inc. (d)59.80 %59.80 %$450 2 NSP-Minnesota50.00 47.00 170 2 NSP-Wisconsin47.00 47.10 N/A1 SPS47.20 46.60 60 2 PSCo44.90 45.20 170 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% (70% for Xcel Energy Inc.). (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2025, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2025:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$2,000 $850 $1,150 PSCo1,200 308 892 NSP-Minnesota800 264 536 SPS600 220 380 NSP-Wisconsin150 - 150 Total$4,750 $1,642 $3,108 (a)These credit facilities mature in December 2029.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2025 and 2024.Term Loan Agreement - In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility. The loan is unsecured and matures Jan. 30, 2027. The term loan includes one financial covenant, requiring Xcel Energy's consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent. Interest is at a rate equal to the Term SOFR rate, plus 85.0 basis points, or an alternate base rate.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2025Year Ended Dec. 31202520242023Borrowing limit$4,750 $4,750 $3,550 $3,550 Amount outstanding at period end1,550 1,550 695 785 Average amount outstanding1,622 1,026 508 491 Maximum amount outstanding2,965 2,965 1,314 1,241 Weighted average interest rate, computed on a daily basis4.14 %4.41 %5.47 %5.12 %Weighted average interest rate at period end3.95 3.95 4.64 5.52 Bilateral Credit Agreement - In April 2025, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2025, NSP-Minnesota had $69 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2025 and 2024, there were $92 million and $42 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $4.75 billion. The amended credit agreements mature in December 2029. --- ## Modified: Wholesale and Commodity Marketing Operations **Key changes:** - Reworded sentence: "PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products." **Prior (2025):** NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCo **Current (2026):** NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCo --- ## Modified: CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY **Key changes:** - Reworded sentence: "31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 Net income1,771 1,771 Other comprehensive loss(1)(1)Dividends declared on common stock ($2.08 per share)(1,148)(1,148)Issuances of common stock5,363,685 13 295 308 Share-based compensation15 (4)11 Balance at Dec." **Prior (2025):** (amounts in millions, except per share data; shares in actual amounts) Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholders' EquitySharesPar ValueAdditional PaidIn CapitalBalance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 Net income1,736 1,736 Other comprehensive income30 30 Dividends declared on common stock ($1.95 per share)(1,066)(1,066)Issuances of common stock5,552,749 14 345 359 Share-based compensation7 (3)4 Balance at Dec. 31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 Net Income1,771 1,771 Other comprehensive loss(1)(1)Dividends declared on common stock ($2.08 per share)(1,148)(1,148)Issuances of common stock5,363,685 13 295 308 Share-based compensation15 (4)11 Balance at Dec. 31, 2023554,941,703 $1,387 $8,465 $7,858 $(94)$17,616 Net income1,936 1,936 Other comprehensive income26 26 Dividends declared on common stock ($2.19 per share)(1,236)(1,236)Issuances of common stock19,423,895 49 1,098 1,147 Share-based compensation38 (5)33 Balance at Dec. 31, 2024574,365,598 $1,436 $9,601 $8,553 $(68)$19,522 See Notes to Consolidated Financial Statements **Current (2026):** (amounts in millions, except per share data; shares in actual amounts) Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholders' EquitySharesPar ValueAdditional PaidIn CapitalBalance at Dec. 31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 Net income1,771 1,771 Other comprehensive loss(1)(1)Dividends declared on common stock ($2.08 per share)(1,148)(1,148)Issuances of common stock5,363,685 13 295 308 Share-based compensation15 (4)11 Balance at Dec. 31, 2023554,941,703 $1,387 $8,465 $7,858 $(94)$17,616 Net Income1,936 1,936 Other comprehensive income26 26 Dividends declared on common stock ($2.19 per share)(1,236)(1,236)Issuances of common stock19,423,895 49 1,098 1,147 Share-based compensation38 (5)33 Balance at Dec. 31, 2024574,365,598 $1,436 $9,601 $8,553 $(68)$19,522 Net income2,018 2,018 Other comprehensive income5 5 Dividends declared on common stock ($2.28 per share)(1,357)(1,357)Issuances of common stock49,235,117 123 3,253 3,376 Share-based compensation52 (7)45 Balance at Dec. 31, 2025623,600,715 $1,559 $12,906 $9,207 $(63)$23,609 See Notes to Consolidated Financial Statements --- ## Modified: Increased risks of regulatory penalties could negatively impact our business. **Key changes:** - Reworded sentence: "The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders." - Reworded sentence: "Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover the costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances." - Reworded sentence: "Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our operational facilities." - Reworded sentence: "The potential for unprecedented load growth and the need for additional generation resources to support such growth may further impact the timing or achievement of our climate goals." - Reworded sentence: "Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover the costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances." **Prior (2025):** Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, 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. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows. **Current (2026):** The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. 20 20 20 Table of Contents Table of Contents The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover the costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our operational facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, 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. The potential for unprecedented load growth and the need for additional generation resources to support such growth may further impact the timing or achievement of our climate goals. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.ITEM 1B - UNRESOLVED STAFF COMMENTSNone.ITEM 1C - CYBERSECURITYAs described in Item 1A - Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover the costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. --- ## Modified: Annual weather-normalized and leap year adjusted natural gas sales growth (decline) **Key changes:** - Reworded sentence: "•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all jurisdictions." **Prior (2025):** •Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions. **Current (2026):** •Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all jurisdictions. --- ## Modified: Additional Information **Key changes:** - Reworded sentence: "Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP." - Reworded sentence: "DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota." **Prior (2025):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. **Current (2026):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. --- ## Modified: Recovery Mechanisms **Key changes:** - Reworded sentence: "Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP." - Reworded sentence: "DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota." **Prior (2025):** MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. **Current (2026):** MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. --- ## Modified: Short-Term Borrowings **Key changes:** - Reworded sentence: "31, 2025Year Ended Dec." - Reworded sentence: "31, 2025, NSP-Minnesota had $69 million outstanding letters of credit under the $75 million Bilateral Credit Agreement." - Reworded sentence: "31, 2025 and 2024, there were $92 million and $42 million of letters of credit outstanding under the credit facilities, respectively." - Reworded sentence: "In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks." - Reworded sentence: "31, 2025, Xcel Energy Inc." **Prior (2025):** Short-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements. Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31202420232022Borrowing limit$3,550 $3,550 $3,550 $3,550 Amount outstanding at period end695 695 785 813 Average amount outstanding133 508 491 552 Maximum amount outstanding695 1,314 1,241 1,357 Weighted average interest rate, computed on a daily basis4.77 %5.47 %5.12 %1.47 %Weighted average interest rate at period end4.64 4.64 5.52 4.66 Bilateral Credit Agreement - In April 2024, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20242023Xcel Energy Inc. (d)59.8 %59.8 %$350 2 NSP-Minnesota47.0 47.7 150 2 NSP-Wisconsin47.1 48.2 N/A1 SPS46.6 46.1 50 2 PSCo45.2 44.8 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2024, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2024:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $235 $1,265 PSCo700 115 585 NSP-Minnesota700 207 493 SPS500 145 355 NSP-Wisconsin150 35 115 Total$3,550 $737 $2,813 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20242023Xcel Energy Inc. (d)59.8 %59.8 %$350 2 NSP-Minnesota47.0 47.7 150 2 NSP-Wisconsin47.1 48.2 N/A1 SPS46.6 46.1 50 2 PSCo45.2 44.8 100 2 **Current (2026):** Short-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements. Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2025Year Ended Dec. 31202520242023Borrowing limit$4,750 $4,750 $3,550 $3,550 Amount outstanding at period end1,550 1,550 695 785 Average amount outstanding1,622 1,026 508 491 Maximum amount outstanding2,965 2,965 1,314 1,241 Weighted average interest rate, computed on a daily basis4.14 %4.41 %5.47 %5.12 %Weighted average interest rate at period end3.95 3.95 4.64 5.52 Bilateral Credit Agreement - In April 2025, NSP-Minnesota's uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2025, NSP-Minnesota had $69 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Letters of Credit - Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2025 and 2024, there were $92 million and $42 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. Credit Facilities - In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $4.75 billion. The amended credit agreements mature in December 2029. Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20252024Xcel Energy Inc. (d)59.80 %59.80 %$450 2 NSP-Minnesota50.00 47.00 170 2 NSP-Wisconsin47.00 47.10 N/A1 SPS47.20 46.60 60 2 PSCo44.90 45.20 170 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% (70% for Xcel Energy Inc.). (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy's consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2025, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2025:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$2,000 $850 $1,150 PSCo1,200 308 892 NSP-Minnesota800 264 536 SPS600 220 380 NSP-Wisconsin150 - 150 Total$4,750 $1,642 $3,108 (a)These credit facilities mature in December 2029.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2025 and 2024.Term Loan Agreement - In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility. The loan is unsecured and matures Jan. 30, 2027. The term loan includes one financial covenant, requiring Xcel Energy's consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent. Interest is at a rate equal to the Term SOFR rate, plus 85.0 basis points, or an alternate base rate.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20252024Xcel Energy Inc. (d)59.80 %59.80 %$450 2 NSP-Minnesota50.00 47.00 170 2 NSP-Wisconsin47.00 47.10 N/A1 SPS47.20 46.60 60 2 PSCo44.90 45.20 170 2 --- ## Modified: CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME **Key changes:** - Reworded sentence: "31202520242023Net income$2,018 $1,936 $1,771 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical losses arising during the period, net of tax (1)(3)(4)Reclassification of losses to net income, net of tax 2 5 2 Derivative instruments:Net fair value increase (decrease), net of tax2 22 (2)Reclassification of losses to net income, net of tax 2 2 3 Total other comprehensive income (loss)5 26 (1)Total comprehensive income$2,023 $1,962 $1,770 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents" **Prior (2025):** (amounts in millions) Year Ended Dec. 31202420232022Net income$1,936 $1,771 $1,736 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical (losses) gains arising during the period, net of tax (3)(4)5 Reclassification of losses to net income, net of tax 5 2 4 Derivative instruments:Net fair value increase (decrease), net of tax22 (2)16 Reclassification of losses to net income, net of tax 2 3 5 Total other comprehensive income (loss)26 (1)30 Total comprehensive income$1,962 $1,770 $1,766 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents **Current (2026):** (amounts in millions) Year Ended Dec. 31202520242023Net income$2,018 $1,936 $1,771 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical losses arising during the period, net of tax (1)(3)(4)Reclassification of losses to net income, net of tax 2 5 2 Derivative instruments:Net fair value increase (decrease), net of tax2 22 (2)Reclassification of losses to net income, net of tax 2 2 3 Total other comprehensive income (loss)5 26 (1)Total comprehensive income$2,023 $1,962 $1,770 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents --- ## Modified: Additional Information **Key changes:** - Reworded sentence: "Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP." - Reworded sentence: "Returns benefits and recovers costs from investments benefiting customers in South Dakota." - Reworded sentence: "Allocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates." **Prior (2025):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. **Current (2026):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. --- ## Modified: Joint Ownership of Generation, Transmission and Gas Facilities **Key changes:** - Reworded sentence: "31, 2025: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$638 $515 59 %Sherco common facilities189 134 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 4 50 CapX2020887 169 51 Total NSP-Minnesota (a)$1,779 $830 Total NSP-Minnesota (a) (a)Projects additionally include $26 million in CWIP." - Reworded sentence: "(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $33 37 %CapX2020169 46 80 Total NSP-Wisconsin (a)$348 $79 Total NSP-Wisconsin (a) (a)Projects additionally include $3 million in CWIP." - Reworded sentence: "56 56 56 Table of Contents Table of Contents" **Prior (2025):** The utility subsidiaries' jointly owned assets as of Dec. 31, 2024: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 Total NSP-Minnesota (a) (a)Projects additionally include $10 million in CWIP. Projects additionally include $10 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $30 37 %CapX2020169 44 80 Total NSP-Wisconsin (a)$348 $74 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 (a)Projects additionally include $28 million in CWIP.Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $30 37 %CapX2020169 44 80 Total NSP-Wisconsin (a)$348 $74 Total NSP-Wisconsin (a) (a)Projects additionally include $1 million in CWIP. Projects additionally include $1 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 Total PSCo (a) (a)Projects additionally include $28 million in CWIP. Projects additionally include $28 million in CWIP. Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. 57 57 57 Table of Contents Table of Contents **Current (2026):** The utility subsidiaries' jointly owned assets as of Dec. 31, 2025: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$638 $515 59 %Sherco common facilities189 134 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 4 50 CapX2020887 169 51 Total NSP-Minnesota (a)$1,779 $830 Total NSP-Minnesota (a) (a)Projects additionally include $26 million in CWIP. Projects additionally include $26 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $33 37 %CapX2020169 46 80 Total NSP-Wisconsin (a)$348 $79 (a)Projects additionally include $3 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$159 $126 76 %Hayden Unit 2152 99 37 Hayden common facilities45 36 53 Craig Units 1 and 282 60 10 Craig common facilities40 28 7 Comanche Unit 3971 233 67 Comanche common facilities29 6 77 Electric transmission:Transmission and other facilities193 76 VariousGas transmission:Rifle, CO to Avon, CO31 10 60 Gas transmission compressor8 3 60 Total PSCo (a)$1,710 $677 (a)Projects additionally include $16 million in CWIP.Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $33 37 %CapX2020169 46 80 Total NSP-Wisconsin (a)$348 $79 Total NSP-Wisconsin (a) (a)Projects additionally include $3 million in CWIP. Projects additionally include $3 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$159 $126 76 %Hayden Unit 2152 99 37 Hayden common facilities45 36 53 Craig Units 1 and 282 60 10 Craig common facilities40 28 7 Comanche Unit 3971 233 67 Comanche common facilities29 6 77 Electric transmission:Transmission and other facilities193 76 VariousGas transmission:Rifle, CO to Avon, CO31 10 60 Gas transmission compressor8 3 60 Total PSCo (a)$1,710 $677 Total PSCo (a) (a)Projects additionally include $16 million in CWIP. Projects additionally include $16 million in CWIP. Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. 56 56 56 Table of Contents Table of Contents --- ## Modified: Other Utility Items **Key changes:** - Reworded sentence: "AFUDC - Alternative Revenue - Certain rate rider mechanisms (including transmission and distribution cost recovery, decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs." - Reworded sentence: "Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned." - Removed sentence: "Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs." - Removed sentence: "This method amortizes costs over the period between refueling outages consistent with rate recovery." - Removed sentence: "An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis." **Prior (2025):** AFUDC - AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy's rate base. AFUDC - Alternative Revenue - Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs - Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsRecently AdoptedSegment Reporting - In November 2023, the FASB issued ASU 2023-07 - Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material.See Note 14 for further information. Recently IssuedIncome Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements. Climate-Related Disclosures - In March 2024, the SEC issued Final Rule 33-11275 - The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements.Disaggregation of Income Statement Expenses - In November 2024, the FASB issued ASU 2024-03 - Disaggregation of Income Statement Expenses, which requires disaggregated disclosure of income statement expenses for public business entities. The ASU is effective for annual periods beginning after Dec. 15, 2026. Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income. **Current (2026):** AFUDC - AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy's rate base. AFUDC - Alternative Revenue - Certain rate rider mechanisms (including transmission and distribution cost recovery, decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsRecently AdoptedIncome Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. Xcel Energy retrospectively implemented this guidance in the year ended Dec. 31, 2025. The adoption impacts were not material.See Note 7 for further information. Recently IssuedGovernment Grants - In December 2025, the FASB issued ASU 2025-10 - Government Grants (Topic 832), which includes amended recognition, measurement and presentation requirements for asset and income-related grants. The ASU is effective for annual and interim reporting periods beginning after Dec. 15, 2028. Xcel Energy is currently evaluating the new guidance, but adoption impacts are expected to be immaterial. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs - Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emissions Allowances - Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. RECs - Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income. --- ## Modified: Station, Location and Unit at Dec. 31, 2025 **Key changes:** - Reworded sentence: "MW (a) (b) (c) (d) (e) (e) Border-Rolette County, ND, 75 Units (f) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (e) (e) (e) (e) (e) (e) Pleasant Valley-Mower County, MN, 100 Units (f) (e) (e) (e) (a)Summer 2025 net dependable capacity." - Reworded sentence: "(d)Four units were retired in 2025." - Reworded sentence: "31, 2025, wind facilities had a weighted-average capacity factor of 44%." - Reworded sentence: "31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 (a)Summer 2025 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units.PSCoStation, Location and Unit at Dec." - Reworded sentence: "31, 2025, wind facilities had a weighted-average capacity factor of 41%." **Prior (2025):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota's wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo's wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 **Current (2026):** MW (a) (b) (c) (d) (e) (e) Border-Rolette County, ND, 75 Units (f) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (e) (e) (e) (e) (e) (e) Pleasant Valley-Mower County, MN, 100 Units (f) (e) (e) (e) (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Four units were retired in 2025. (e)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 44%. For solar projects placed in service in 2025, factors will be available after a full year of operations. (f)Repowered in 2025. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 (a)Summer 2025 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units.PSCoStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 (e)Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Solar:Rocky Mountain Solar-Keenesburg, CO, 87 unitsSolar2025325 (f)Total6,528 (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Pawnee coal plant was retired in 2025 and completed conversion to natural gas in 2026.(f)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 41%. For solar projects placed in service in 2025, factors will be available after a full year of operations. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 --- ## Modified: Station, Location and Unit at Dec. 31, 2025 **Key changes:** - Reworded sentence: "MW (a) (b) (c) Hayden-Hayden, CO, 2 Units (d) (e) (f) (f) (f) (a)Summer 2025 net dependable capacity." - Reworded sentence: "(e)Pawnee coal plant was retired in 2025 and completed conversion to natural gas in 2026." - Reworded sentence: "31, 2025, wind facilities had a weighted-average capacity factor of 41%." - Reworded sentence: "31, 2025FuelInstalledMW (a)Steam:Cunningham-Hobbs, NM, 1 UnitNatural Gas1957 - 1965183 Harrington-Amarillo, TX 3 UnitsNatural Gas2024 - 20251,018 Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 Plant X-Earth, TX, 1 UnitNatural Gas1952 - 1964190 Tolk-Muleshoe, TX, 2 UnitsCoal1982 - 19851,067 Combustion Turbine:Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 Wind:Hale-Plainview, TX, 239 UnitsWind2019478 (b)Sagamore-Dora, NM, 240 UnitsWind2020508 (b)Total5,101 (a)Summer 2025 net dependable capacity." - Reworded sentence: "31, 2025 SPS' wind facilities had a weighted-average capacity factor of 47%." **Prior (2025):** MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota's wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo's wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 **Current (2026):** MW (a) (b) (c) (d) (e) (e) Border-Rolette County, ND, 75 Units (f) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (e) (e) (e) (e) (e) (e) Pleasant Valley-Mower County, MN, 100 Units (f) (e) (e) (e) (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota's ownership of 59%. (c)RDF is made from municipal solid waste. (d)Four units were retired in 2025. (e)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 44%. For solar projects placed in service in 2025, factors will be available after a full year of operations. (f)Repowered in 2025. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 (a)Summer 2025 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units.PSCoStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 (e)Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (f)Cheyenne Ridge, CO, 229 unitsWind2020477 (f)Solar:Rocky Mountain Solar-Keenesburg, CO, 87 unitsSolar2025325 (f)Total6,528 (a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity.(b)Based on PSCo's ownership of 67%.(c)Based on PSCo's ownership of 10%. (d)Based on PSCo's ownership of 76% of Unit 1 and 37% of Unit 2.(e)Pawnee coal plant was retired in 2025 and completed conversion to natural gas in 2026.(f)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 41%. For solar projects placed in service in 2025, factors will be available after a full year of operations. NSP-WisconsinStation, Location and Unit at Dec. 31, 2025FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 1 UnitNatural Gas2025206 (c)Reciprocating Generation:Wheaton-Eau Claire, WI, 5 UnitsNatural Gas202540 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total557 --- ## Modified: Our utilities have significant risks associated with wildfires. **Key changes:** - Reworded sentence: "In recent years, wildfires have impacted the utility industry." - Reworded sentence: "Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs." - Reworded sentence: "Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas." - Reworded sentence: "Additionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, our risk management programs may not be effective to protect against significant adverse market fluctuations and our results of operations, financial condition or cash flows could be materially impacted." - Removed sentence: "Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance." **Prior (2025):** A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity. A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations. We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy's results of operations, financial condition or cash flows could be materially impacted. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. **Current (2026):** In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in availability of vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other environmental factors have increased both the frequency and duration of fire weather conditions and the potential impact of an event. The expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Also, wildfires could jeopardize Xcel Energy's electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Our current wildfire mitigation initiatives may not be effective in preventing or reducing ignitions and wildfire-related losses. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, damage amounts could exceed our coverage (as experienced with the Marshall Wildfire settlement in 2025) and negatively impact our results of operations, financial condition or cash flows. 16 16 16 Table of Contents Table of Contents We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Additionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, our risk management programs may not be effective to protect against significant adverse market fluctuations and our results of operations, financial condition or cash flows could be materially impacted. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution.Actions of our employees, directors, third-party contractors or suppliers could expose us to reputational risks.We could suffer negative impacts to our reputation as a result of actual or perceived fraud, misconduct, legal or regulatory violations, violations of corporate policies, inappropriate use of social media, or other actions by our employees, directors, third-party contractors or suppliers. Reputational damage could have a material adverse effect and could result in negative customer perception, litigation and increased regulatory oversight.Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers. We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Additionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, our risk management programs may not be effective to protect against significant adverse market fluctuations and our results of operations, financial condition or cash flows could be materially impacted. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. --- ## Modified: A cybersecurity incident or security breach could have a material effect on our business. **Key changes:** - Reworded sentence: "Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability." - Reworded sentence: "Advancements in artificial intelligence and large language models may increase cybersecurity threats and operational risks." - Reworded sentence: "Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance." - Reworded sentence: "Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation." **Prior (2025):** We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. 20 20 20 Table of Contents Table of Contents Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, 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. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. **Current (2026):** We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy's generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy's generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations, could also negatively impact our business. Advancements in artificial intelligence and large language models may increase cybersecurity threats and operational risks. Threat actors may use artificial intelligence to enhance their attacks, increasing the frequency, sophistication and potential impact of cyber incidents affecting our IT and OT environment. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. --- ## Modified: Employee Benefits **Key changes:** - Reworded sentence: "31, 2025, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which remains unchanged from the rate set at Dec." - Reworded sentence: "31, 2025, which remains unchanged from the rate set in 2024." - Reworded sentence: "Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.78% and 5.66% at Dec." - Reworded sentence: "If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2026 pension costs, net of the effects of regulation: Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$22 Discount rate (4) - Discount rate Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits." - Reworded sentence: "31, 2025, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%." **Prior (2025):** We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. 36 36 36 Table of Contents Table of Contents At Dec. 31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set at Dec. 31, 2023. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2024, which is a 125 basis point increase from the rate set in 2023. Xcel Energy's pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan's funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec. 31, 2024. This represents a 39 basis point and 34 basis point increase, respectively, from 2023. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation:Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy's actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.As of Dec. 31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy's retiree medical plan. Funding contributions in 2024 were $100 million and will be $125 million in 2025. In future years contributions will decrease slightly but then remain relatively consistent. Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023.The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2024).Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023. The expected decrease in 2025 is primarily due to the absence of a pension settlement.Pension funding contributions across all four of Xcel Energy's pension plans, both voluntary and required, for 2022 - 2025:•$125 million in January 2025.•$100 million in 2024.•$50 million in 2023.•$50 million in 2022.Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2025. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2024.See Note 11 to the consolidated financial statements for further information.Nuclear DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. At Dec. 31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set at Dec. 31, 2023. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2024, which is a 125 basis point increase from the rate set in 2023. Xcel Energy's pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan's funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec. 31, 2024. This represents a 39 basis point and 34 basis point increase, respectively, from 2023. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation:Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy's actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.As of Dec. 31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy's retiree medical plan. Funding contributions in 2024 were $100 million and will be $125 million in 2025. In future years contributions will decrease slightly but then remain relatively consistent. Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023.The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. At Dec. 31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set at Dec. 31, 2023. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2024, which is a 125 basis point increase from the rate set in 2023. Xcel Energy's pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan's funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios. Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec. 31, 2024. This represents a 39 basis point and 34 basis point increase, respectively, from 2023. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected. If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation: Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Discount rate Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy's actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate. As of Dec. 31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy's retiree medical plan. Funding contributions in 2024 were $100 million and will be $125 million in 2025. In future years contributions will decrease slightly but then remain relatively consistent. Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023. The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2024).Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023. The expected decrease in 2025 is primarily due to the absence of a pension settlement.Pension funding contributions across all four of Xcel Energy's pension plans, both voluntary and required, for 2022 - 2025:•$125 million in January 2025.•$100 million in 2024.•$50 million in 2023.•$50 million in 2022.Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2025. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2024.See Note 11 to the consolidated financial statements for further information.Nuclear DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2024). Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023. The expected decrease in 2025 is primarily due to the absence of a pension settlement. Pension funding contributions across all four of Xcel Energy's pension plans, both voluntary and required, for 2022 - 2025: •$125 million in January 2025. •$100 million in 2024. •$50 million in 2023. •$50 million in 2022. Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2025. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below. •NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability. •PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset. •Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions. •PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2024. See Note 11 to the consolidated financial statements for further information. **Current (2026):** We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. At Dec. 31, 2025, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which remains unchanged from the rate set at Dec. 31, 2024. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2025, which remains unchanged from the rate set in 2024. Xcel Energy's pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan's funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios. Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.78% and 5.66% at Dec. 31, 2025, respectively. This represents a 10 basis point and 22 basis point decrease, respectively, from 2024. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected. If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2026 pension costs, net of the effects of regulation: Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$22 Discount rate (4) - Discount rate Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy's actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate. As of Dec. 31, 2025, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy's retiree medical plan. 37 37 37 Table of Contents Table of Contents Funding contributions in 2025 were $125 million and will be $75 million in 2026. In future years contributions will remain relatively consistent. Investment returns were more than the assumed levels in 2025 and 2023, but were less than the assumed levels in 2024.The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2025).Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $85 million in 2026, while the actual pension costs were $59 million in 2025 and $79 million in 2024.Pension funding contributions across all four of Xcel Energy's pension plans, both voluntary and required, for 2023 - 2026:•$75 million in January 2026.•$125 million in 2025.•$100 million in 2024.•$50 million in 2023.Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million in 2025 and $11 million during 2024 and 2023, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2026. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2025.See Note 11 to the consolidated financial statements for further information.Nuclear DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.6 billion in 2025 and $2.5 billion in 2024. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed and was approved by the MPUC in May 2025. The following assumptions have a significant effect on the estimated nuclear obligation:Timing - Decommissioning cost estimates are impacted by each facility's retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit's operating license with the NRC. NSP-Minnesota's current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. During 2025, the Commission approved extended lives for Prairie Island Unit 1 and Unit 2 and Monticello (2053, 2054, and 2050, respectively) in the Upper Midwest Resource Plan. A request to update authorized retirement dates and related decommissioning estimates to incorporate the extended lives are pending with the Commission. These will be incorporated in decommissioning estimates once additional approvals have been received.The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Funding contributions in 2025 were $125 million and will be $75 million in 2026. In future years contributions will remain relatively consistent. Investment returns were more than the assumed levels in 2025 and 2023, but were less than the assumed levels in 2024.The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2025).Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $85 million in 2026, while the actual pension costs were $59 million in 2025 and $79 million in 2024.Pension funding contributions across all four of Xcel Energy's pension plans, both voluntary and required, for 2023 - 2026:•$75 million in January 2026.•$125 million in 2025.•$100 million in 2024.•$50 million in 2023.Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million in 2025 and $11 million during 2024 and 2023, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2026. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2025.See Note 11 to the consolidated financial statements for further information. Funding contributions in 2025 were $125 million and will be $75 million in 2026. In future years contributions will remain relatively consistent. Investment returns were more than the assumed levels in 2025 and 2023, but were less than the assumed levels in 2024. The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2025). Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $85 million in 2026, while the actual pension costs were $59 million in 2025 and $79 million in 2024. Pension funding contributions across all four of Xcel Energy's pension plans, both voluntary and required, for 2023 - 2026: •$75 million in January 2026. •$125 million in 2025. •$100 million in 2024. •$50 million in 2023. Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million in 2025 and $11 million during 2024 and 2023, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2026. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below. •NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability. •PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset. •Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions. •PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2025. See Note 11 to the consolidated financial statements for further information. Nuclear DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.6 billion in 2025 and $2.5 billion in 2024. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed and was approved by the MPUC in May 2025. The following assumptions have a significant effect on the estimated nuclear obligation:Timing - Decommissioning cost estimates are impacted by each facility's retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit's operating license with the NRC. NSP-Minnesota's current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. During 2025, the Commission approved extended lives for Prairie Island Unit 1 and Unit 2 and Monticello (2053, 2054, and 2050, respectively) in the Upper Midwest Resource Plan. A request to update authorized retirement dates and related decommissioning estimates to incorporate the extended lives are pending with the Commission. These will be incorporated in decommissioning estimates once additional approvals have been received.The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. --- ## Modified: Statement of Income Analysis **Key changes:** - Reworded sentence: "26 26 26 Table of Contents Table of Contents As a result, weather deviations from normal levels can affect Xcel Energy's financial performance." - Reworded sentence: "HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit." - Reworded sentence: "Industrial customers are less sensitive to weather." - Reworded sentence: "Percentage increase (decrease) in normal and actual HDD, CDD and THI:2025 vs.Normal2024 vs.Normal2025 vs." - Reworded sentence: "Industrial customers are less sensitive to weather." **Prior (2025):** The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. 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. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. 26 26 26 Table of Contents Table of Contents HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather.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. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2024 vs.Normal2023 vs.Normal2024 vs. 2023HDD(15.4)%(7.3)%(9.8)%CDD28.1 5.2 23 THI(11.2)16.0 (22.5)Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2024 vs. Normal2023 vs. Normal2024 vs. 2023Retail electric$(0.008)$0.013 $(0.021)Decoupling and sales true-up0.047 (0.007)0.054 Electric total$0.039 $0.006 $0.033 Firm natural gas(0.070)(0.010)(0.060)Decoupling$0.027 $0.013 $0.014 Gas total$(0.043)$0.003 $(0.046)Total$(0.004)$0.009 $(0.013)Sales - Sales growth (decline) for actual and weather-normalized sales:2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(4.1)%3.9 %0.7 %(3.5)%(0.4)%Electric C&I(2.6) - 9.3 (1.9)1.7 Total retail electric sales(3.1)1.3 7.8 (2.4)1.1 Firm natural gas sales(8.0)(6.9)N/A(7.5)(7.2)2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential0.2 %0.9 %(1.2)%(1.5)%0.2 %Electric C&I(1.7)(1.1)9.3 (1.6)1.7 Total retail electric sales(1.1)(0.4)7.4 (1.5)1.3 Firm natural gas sales(1.1)0.6 N/A(2.5)(0.2)2024 vs. 2023 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(0.1)%0.7 %(1.5)%(1.8)%(0.1)%Electric C&I(2.0)(1.4)9.0 (1.8)1.5 Total retail electric sales(1.4)(0.7)7.1 (1.8)1.0 Firm natural gas sales(1.7) - N/A(3.1)(0.7)Annual weather-normalized and leap year adjusted electric sales growth (decline)•NSP-Minnesota - Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector.•PSCo - Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining. •SPS - Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining. •NSP-Wisconsin - Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.Annual weather-normalized and leap year adjusted natural gas sales growth (decline)•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions. Electric RevenuesElectric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of electric fuel and purchase power(479)PTCs flowed back to customers (offset by lower ETR)(302)Wholesale generation revenues(96)Sherco Unit 3 2011 outage refunds(47)Regulatory rate outcomes (MN, CO, TX, and NM)372 Non-fuel riders169 Conservation and demand side management (offset in expense)102 Estimated impact of weather (net of sales true-up)24 Other, net(42)Total decrease$(299) HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather.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. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2024 vs.Normal2023 vs.Normal2024 vs. 2023HDD(15.4)%(7.3)%(9.8)%CDD28.1 5.2 23 THI(11.2)16.0 (22.5)Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2024 vs. Normal2023 vs. Normal2024 vs. 2023Retail electric$(0.008)$0.013 $(0.021)Decoupling and sales true-up0.047 (0.007)0.054 Electric total$0.039 $0.006 $0.033 Firm natural gas(0.070)(0.010)(0.060)Decoupling$0.027 $0.013 $0.014 Gas total$(0.043)$0.003 $(0.046)Total$(0.004)$0.009 $(0.013)Sales - Sales growth (decline) for actual and weather-normalized sales:2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(4.1)%3.9 %0.7 %(3.5)%(0.4)%Electric C&I(2.6) - 9.3 (1.9)1.7 Total retail electric sales(3.1)1.3 7.8 (2.4)1.1 Firm natural gas sales(8.0)(6.9)N/A(7.5)(7.2)2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential0.2 %0.9 %(1.2)%(1.5)%0.2 %Electric C&I(1.7)(1.1)9.3 (1.6)1.7 Total retail electric sales(1.1)(0.4)7.4 (1.5)1.3 Firm natural gas sales(1.1)0.6 N/A(2.5)(0.2) HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. 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. Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2024 vs.Normal2023 vs.Normal2024 vs. 2023HDD(15.4)%(7.3)%(9.8)%CDD28.1 5.2 23 THI(11.2)16.0 (22.5) Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2024 vs. Normal2023 vs. Normal2024 vs. 2023Retail electric$(0.008)$0.013 $(0.021)Decoupling and sales true-up0.047 (0.007)0.054 Electric total$0.039 $0.006 $0.033 Firm natural gas(0.070)(0.010)(0.060)Decoupling$0.027 $0.013 $0.014 Gas total$(0.043)$0.003 $(0.046)Total$(0.004)$0.009 $(0.013) Sales - Sales growth (decline) for actual and weather-normalized sales: 2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(4.1)%3.9 %0.7 %(3.5)%(0.4)%Electric C&I(2.6) - 9.3 (1.9)1.7 Total retail electric sales(3.1)1.3 7.8 (2.4)1.1 Firm natural gas sales(8.0)(6.9)N/A(7.5)(7.2) 2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential0.2 %0.9 %(1.2)%(1.5)%0.2 %Electric C&I(1.7)(1.1)9.3 (1.6)1.7 Total retail electric sales(1.1)(0.4)7.4 (1.5)1.3 Firm natural gas sales(1.1)0.6 N/A(2.5)(0.2) **Current (2026):** The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. 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. 26 26 26 Table of Contents Table of Contents As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. 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. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2025 vs.Normal2024 vs.Normal2025 vs. 2024HDD(6.2)%(15.4)%8.7 %CDD(4.9)28.1 (23.5)THI11.2 (11.2)26.8 Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2025 vs. Normal2024 vs. Normal2025 vs. 2024Retail electric$(0.015)$(0.008)$(0.007)Decoupling and sales true-up - 0.047 (0.047)Electric total$(0.015)$0.039 $(0.054)Firm natural gas(0.033)(0.070)0.037 Decoupling0.005 0.027 (0.022)Gas total$(0.028)$(0.043)$0.015 Total$(0.043)$(0.004)$(0.039)Sales - Sales growth (decline) for actual and weather-normalized sales:2025 vs. 2024NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential5.7 %(1.6)%(1.5)%6.0 %1.9 %Electric C&I0.3 0.1 5.5 0.7 2.0 Total retail electric sales2.0 (0.5)4.2 2.2 1.9 Firm natural gas sales12.6 (2.1)N/A16.2 3.4 2025 vs. 2024NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.3 %1.4 %3.9 %1.7 %1.7 %Electric C&I(0.6)1.4 6.1 0.1 2.1 Total retail electric sales - 1.3 5.6 0.6 2.0 Firm natural gas sales - (2.9)N/A2.0 (1.7)2025 vs. 2024 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.5 %1.7 %4.3 %2.1 %2.0 %Electric C&I(0.3)1.6 6.3 0.4 2.4 Total retail electric sales0.3 1.6 5.8 0.9 2.2 Firm natural gas sales0.6 (2.4)N/A2.6 (1.2)Annual weather-normalized and leap year adjusted electric sales growth (decline)•NSP-Minnesota - Residential sales increased due to customer growth (1.1%) and use per customer (0.4%). The decrease in C&I sales was due to lower use per customer.•PSCo - Residential sales increased due to customer growth (1.1%) and use per customer (0.6%). The increase in C&I sales was due to higher use per customer, particularly in the information and energy sectors. •SPS - Residential sales increased due to increased use per customer (3.6%) and customer growth (0.7%). The increase in C&I sales was due to higher use per customer, primarily driven by the energy sector. •NSP-Wisconsin - Residential sales increased due to increased use per customer (1.1%) and customer growth (0.9%). The increase in C&I sales was due to customer growth.Annual weather-normalized and leap year adjusted natural gas sales growth (decline)•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all jurisdictions.Electric RevenuesElectric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes. As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. 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. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2025 vs.Normal2024 vs.Normal2025 vs. 2024HDD(6.2)%(15.4)%8.7 %CDD(4.9)28.1 (23.5)THI11.2 (11.2)26.8 Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2025 vs. Normal2024 vs. Normal2025 vs. 2024Retail electric$(0.015)$(0.008)$(0.007)Decoupling and sales true-up - 0.047 (0.047)Electric total$(0.015)$0.039 $(0.054)Firm natural gas(0.033)(0.070)0.037 Decoupling0.005 0.027 (0.022)Gas total$(0.028)$(0.043)$0.015 Total$(0.043)$(0.004)$(0.039)Sales - Sales growth (decline) for actual and weather-normalized sales:2025 vs. 2024NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential5.7 %(1.6)%(1.5)%6.0 %1.9 %Electric C&I0.3 0.1 5.5 0.7 2.0 Total retail electric sales2.0 (0.5)4.2 2.2 1.9 Firm natural gas sales12.6 (2.1)N/A16.2 3.4 As a result, weather deviations from normal levels can affect Xcel Energy's financial performance. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. 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. Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2025 vs.Normal2024 vs.Normal2025 vs. 2024HDD(6.2)%(15.4)%8.7 %CDD(4.9)28.1 (23.5)THI11.2 (11.2)26.8 Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:2025 vs. Normal2024 vs. Normal2025 vs. 2024Retail electric$(0.015)$(0.008)$(0.007)Decoupling and sales true-up - 0.047 (0.047)Electric total$(0.015)$0.039 $(0.054)Firm natural gas(0.033)(0.070)0.037 Decoupling0.005 0.027 (0.022)Gas total$(0.028)$(0.043)$0.015 Total$(0.043)$(0.004)$(0.039) Sales - Sales growth (decline) for actual and weather-normalized sales: 2025 vs. 2024NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential5.7 %(1.6)%(1.5)%6.0 %1.9 %Electric C&I0.3 0.1 5.5 0.7 2.0 Total retail electric sales2.0 (0.5)4.2 2.2 1.9 Firm natural gas sales12.6 (2.1)N/A16.2 3.4 2025 vs. 2024NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.3 %1.4 %3.9 %1.7 %1.7 %Electric C&I(0.6)1.4 6.1 0.1 2.1 Total retail electric sales - 1.3 5.6 0.6 2.0 Firm natural gas sales - (2.9)N/A2.0 (1.7)2025 vs. 2024 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.5 %1.7 %4.3 %2.1 %2.0 %Electric C&I(0.3)1.6 6.3 0.4 2.4 Total retail electric sales0.3 1.6 5.8 0.9 2.2 Firm natural gas sales0.6 (2.4)N/A2.6 (1.2)Annual weather-normalized and leap year adjusted electric sales growth (decline)•NSP-Minnesota - Residential sales increased due to customer growth (1.1%) and use per customer (0.4%). The decrease in C&I sales was due to lower use per customer.•PSCo - Residential sales increased due to customer growth (1.1%) and use per customer (0.6%). The increase in C&I sales was due to higher use per customer, particularly in the information and energy sectors. •SPS - Residential sales increased due to increased use per customer (3.6%) and customer growth (0.7%). The increase in C&I sales was due to higher use per customer, primarily driven by the energy sector. •NSP-Wisconsin - Residential sales increased due to increased use per customer (1.1%) and customer growth (0.9%). The increase in C&I sales was due to customer growth.Annual weather-normalized and leap year adjusted natural gas sales growth (decline)•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all jurisdictions.Electric RevenuesElectric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes. 2025 vs. 2024NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.3 %1.4 %3.9 %1.7 %1.7 %Electric C&I(0.6)1.4 6.1 0.1 2.1 Total retail electric sales - 1.3 5.6 0.6 2.0 Firm natural gas sales - (2.9)N/A2.0 (1.7) --- ## Modified: Natural Gas Revenues **Key changes:** - Reworded sentence: "(Millions of Dollars)2025 vs." - Reworded sentence: "Electric fuel and purchased power expenses increased $173 million in 2025." - Reworded sentence: "Natural gas sold and transported increased $90 million in 2025." **Prior (2025):** Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. (Millions of Dollars)2024 vs. 2023Recovery of lower cost of natural gas$(496)Estimated impact of weather (net of decoupling)(35)Retail sales decline (net of decoupling)(1)Regulatory rate outcomes (MN, WI, CO, and ND)91 Infrastructure and integrity riders8 Other, net18 Total decrease$(415) Electric Fuel and Purchased Power - Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of 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 $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes. 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 $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes. **Current (2026):** Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. (Millions of Dollars)2025 vs. 2024Recovery of higher cost of natural gas$92 Regulatory rate outcomes (CO)84 Conservation revenue (offset in expense)47 Estimated impact of weather (net of decoupling)11 Retail sales decline (net of decoupling)(13)Other, net1 Total increase$222 Electric Fuel and Purchased Power - Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses increased $173 million in 2025. The increase is primarily due to increased commodity prices and transmission expense. Cost of Natural Gas Sold and Transported - Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Natural gas sold and transported increased $90 million in 2025. The increase is primarily due to increased commodity prices and volumes, partially offset by timing of fuel recovery mechanisms. --- ## Modified: Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS) **Key changes:** - Reworded sentence: "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." - Reworded sentence: "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." - Reworded sentence: "The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:(Millions of Dollars)20252024GAAP net income$2,018 $1,936 Sherco Unit 3 2011 outage refunds - 47 Marshall Wildfire litigation (a)298 - Less: tax effect of adjustments(77)(13)Ongoing earnings (b)$2,239 $1,969 (a)Includes $2 million of interest costs associated with short-term debt used to pay settlement, which is presented as interest expense on the consolidated statements of income.(b)Amounts may not add due to rounding.Twelve Months Ended Dec." - Reworded sentence: "31, 2025Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.53 $ - $1.53 PSCo1.15 0.38 1.53 SPS0.67 - 0.67 NSP-Wisconsin0.27 - 0.27 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.65 0.38 4.03 Xcel Energy Inc." - Reworded sentence: "In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues." **Prior (2025):** 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 is calculated by dividing the net income or loss of each subsidiary, 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 of 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 EPS, 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. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:(Millions of Dollars)20242023GAAP net income$1,936 $1,771 Loss on Comanche Unit 3 litigation - 35 Workforce reduction expenses - 72 Sherco Unit 3 2011 outage refunds47 - Less: tax effect of adjustments(13)(27)Ongoing earnings (a)$1,969 $1,851 (a)Amounts may not add due to rounding.Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo1.39 - 1.39 SPS0.70 - 0.70 NSP-Wisconsin0.24 - 0.24 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33) - (0.33)Total (a)$3.44 0.06 $3.50 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 - 0.25 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31) - (0.31)Total (a)$3.21 0.14 $3.35 (a)Amounts may not add due to rounding.Adjustments to GAAP net income include:Sherco Unit 3 2011 Outage Refunds - NSP-Minnesota's Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage. Comanche Unit 3 Litigation - In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs.Workforce Reduction - In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs and streamline the organization for long-term success. Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program. Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings: (Millions of Dollars)20242023GAAP net income$1,936 $1,771 Loss on Comanche Unit 3 litigation - 35 Workforce reduction expenses - 72 Sherco Unit 3 2011 outage refunds47 - Less: tax effect of adjustments(13)(27)Ongoing earnings (a)$1,969 $1,851 Ongoing earnings (a) (a)Amounts may not add due to rounding. Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo1.39 - 1.39 SPS0.70 - 0.70 NSP-Wisconsin0.24 - 0.24 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33) - (0.33)Total (a)$3.44 0.06 $3.50 Regulated utility (a) Total (a) Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 - 0.25 Earnings from equity method investments - WYCO0.04 - 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31) - (0.31)Total (a)$3.21 0.14 $3.35 PSCo (a) Regulated utility (a) Total (a) (a)Amounts may not add due to rounding. Adjustments to GAAP net income include: Sherco Unit 3 2011 Outage Refunds - NSP-Minnesota's Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage. Comanche Unit 3 Litigation - In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs. Workforce Reduction - In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs and streamline the organization for long-term success. Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program. Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023. 25 25 25 Table of Contents Table of Contents Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments - WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc. and Other(0.33)(0.31)GAAP Diluted EPS (a)3.44 3.21 Loss on Comanche Unit 3 litigation - 0.05 Workforce reduction expenses - 0.09 Sherco Unit 3 2011 outage refunds0.06 - Ongoing Diluted EPS (a)$3.50 $3.35 (a)Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2024 Comparison with 2023Xcel Energy - GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota - GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges. PSCo - GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges. SPS - GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth.NSP-Wisconsin - GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation.Xcel Energy Inc. and Other - Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.Changes in Diluted EPSComponents significantly contributing to changes in 2024 EPS compared with 2023:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS - 2023$3.21 Components of change - 2024 vs. 2023Electric regulatory rate outcomes and riders0.73 Higher other income, net0.16 Natural gas regulatory rate outcomes and riders0.14 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Higher depreciation and amortization(0.40)Interest charges, net of AFUDC - debt(0.24)Higher O&M expenses(0.13)Sherco Unit 3 2011 outage refunds(0.06)Other, net(0.11)GAAP diluted EPS - 2024$3.44 Sherco Unit 3 2011 outage refunds0.06 Ongoing diluted EPS - 2024$3.50 ROE for Xcel Energy and its utility subsidiaries:20242023ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.07 %9.46 %8.82 %9.11 %PSCo7.63 7.63 7.32 7.77 SPS9.57 9.57 9.80 9.98 NSP-Wisconsin8.98 8.98 10.38 10.67 Utility Subsidiaries8.55 8.69 8.45 8.79 Xcel Energy10.42 10.61 10.33 10.79 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.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. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments - WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc. and Other(0.33)(0.31)GAAP Diluted EPS (a)3.44 3.21 Loss on Comanche Unit 3 litigation - 0.05 Workforce reduction expenses - 0.09 Sherco Unit 3 2011 outage refunds0.06 - Ongoing Diluted EPS (a)$3.50 $3.35 (a)Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2024 Comparison with 2023Xcel Energy - GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota - GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges. PSCo - GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges. SPS - GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth.NSP-Wisconsin - GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation. **Current (2026):** 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 EPS, 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. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:(Millions of Dollars)20252024GAAP net income$2,018 $1,936 Sherco Unit 3 2011 outage refunds - 47 Marshall Wildfire litigation (a)298 - Less: tax effect of adjustments(77)(13)Ongoing earnings (b)$2,239 $1,969 (a)Includes $2 million of interest costs associated with short-term debt used to pay settlement, which is presented as interest expense on the consolidated statements of income.(b)Amounts may not add due to rounding.Twelve Months Ended Dec. 31, 2025Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.53 $ - $1.53 PSCo1.15 0.38 1.53 SPS0.67 - 0.67 NSP-Wisconsin0.27 - 0.27 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.65 0.38 4.03 Xcel Energy Inc. and Other(0.23) - (0.23)Total (a)$3.42 0.38 $3.80 Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo 1.39 - 1.39 SPS0.70 - 0.70 NSP-Wisconsin0.24 - 0.24 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33) - (0.33)Total (a)$3.44 0.06 $3.50 (a)Amounts may not add due to rounding.Adjustments to GAAP net income include:Sherco Unit 3 2011 Outage Refunds - NSP-Minnesota's Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues. Marshall Wildfire Litigation - In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation. In the fourth quarter of 2025, an additional $12 million was recognized for estimated remaining settlement costs as well as legal and other costs. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings: (Millions of Dollars)20252024GAAP net income$2,018 $1,936 Sherco Unit 3 2011 outage refunds - 47 Marshall Wildfire litigation (a)298 - Less: tax effect of adjustments(77)(13)Ongoing earnings (b)$2,239 $1,969 Marshall Wildfire litigation (a) Ongoing earnings (b) (a)Includes $2 million of interest costs associated with short-term debt used to pay settlement, which is presented as interest expense on the consolidated statements of income. (b)Amounts may not add due to rounding. Twelve Months Ended Dec. 31, 2025Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.53 $ - $1.53 PSCo1.15 0.38 1.53 SPS0.67 - 0.67 NSP-Wisconsin0.27 - 0.27 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.65 0.38 4.03 Xcel Energy Inc. and Other(0.23) - (0.23)Total (a)$3.42 0.38 $3.80 Regulated utility (a) Total (a) Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo 1.39 - 1.39 SPS0.70 - 0.70 NSP-Wisconsin0.24 - 0.24 Earnings from equity method investments - WYCO0.03 - 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33) - (0.33)Total (a)$3.44 0.06 $3.50 Regulated utility (a) Total (a) (a)Amounts may not add due to rounding. Adjustments to GAAP net income include: Sherco Unit 3 2011 Outage Refunds - NSP-Minnesota's Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues. Marshall Wildfire Litigation - In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation. In the fourth quarter of 2025, an additional $12 million was recognized for estimated remaining settlement costs as well as legal and other costs. 25 25 25 Table of Contents Table of Contents Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:Diluted Earnings (Loss) Per Share20252024NSP-Minnesota$1.53 $1.41 PSCo1.15 1.39 SPS0.67 0.70 NSP-Wisconsin0.27 0.24 Earnings from equity method investments - WYCO0.03 0.03 Regulated utility (a)3.65 3.76 Xcel Energy Inc. and Other(0.23)(0.33)GAAP diluted EPS (a)$3.42 $3.44 Sherco Unit 3 2011 outage refunds - 0.06 Marshall Wildfire settlement0.38 - Ongoing diluted EPS (a)$3.80 $3.50 (a)Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2025 Comparison with 2024Xcel Energy - GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024. The change in ongoing EPS was driven by increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation and O&M expenses.Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota - GAAP earnings increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024. Ongoing earnings increased due to higher recovery of electric infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges.PSCo - GAAP earnings decreased $0.24 per share and ongoing earnings increased $0.14 per share for 2025 (difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Non-GAAP Financial Measures for reconciliation from GAAP to ongoing earnings). Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M charges.SPS - GAAP and ongoing earnings decreased $0.03 per share for 2025 . The decrease was driven by increased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher recovery of electric infrastructure investments. NSP-Wisconsin - GAAP and ongoing earnings increased $0.03 per share for 2025. The increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and O&M expenses.Xcel Energy Inc. and Other - Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels.Changes in Diluted EPSComponents significantly contributing to changes in 2025 EPS compared with 2024:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS - 2024$3.44 Components of change - 2025 vs. 2024Higher electric revenues1.27 Higher natural gas revenues0.29 Higher AFUDC equity & debt0.27 Marshall Wildfire settlement(0.38)Higher interest charges(0.28)Higher depreciation and amortization(0.28)Higher O&M expenses(0.25)Higher electric fuel and purchased power (a)(0.23)Common equity financing(0.18)Higher costs of natural gas sold and transported (a)(0.12)Other, net(0.13)GAAP diluted EPS - 2025$3.42 Marshall Wildfire settlement0.38 Ongoing diluted EPS - 2025$3.80 (a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.ROE for Xcel Energy and its utility subsidiaries:20252024ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.19 %9.19 %9.07 %9.46 %PSCo5.66 7.55 7.63 7.63 SPS8.70 8.70 9.57 9.57 NSP-Wisconsin9.09 9.09 8.98 8.98 Utility Subsidiaries7.60 8.40 8.55 8.69 Xcel Energy9.36 10.38 10.42 10.61 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.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. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:Diluted Earnings (Loss) Per Share20252024NSP-Minnesota$1.53 $1.41 PSCo1.15 1.39 SPS0.67 0.70 NSP-Wisconsin0.27 0.24 Earnings from equity method investments - WYCO0.03 0.03 Regulated utility (a)3.65 3.76 Xcel Energy Inc. and Other(0.23)(0.33)GAAP diluted EPS (a)$3.42 $3.44 Sherco Unit 3 2011 outage refunds - 0.06 Marshall Wildfire settlement0.38 - Ongoing diluted EPS (a)$3.80 $3.50 (a)Amounts may not add due to rounding.Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2025 Comparison with 2024Xcel Energy - GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024. The change in ongoing EPS was driven by increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation and O&M expenses.Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota - GAAP earnings increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024. Ongoing earnings increased due to higher recovery of electric infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges.PSCo - GAAP earnings decreased $0.24 per share and ongoing earnings increased $0.14 per share for 2025 (difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Non-GAAP Financial Measures for reconciliation from GAAP to ongoing earnings). Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M charges.SPS - GAAP and ongoing earnings decreased $0.03 per share for 2025 . The decrease was driven by increased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher recovery of electric infrastructure investments. NSP-Wisconsin - GAAP and ongoing earnings increased $0.03 per share for 2025. The increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and O&M expenses. --- ## Modified: Xcel Energy Inc. and Other Results **Key changes:** - Reworded sentence: "and its nonregulated businesses: (Millions of Dollars)20252024Xcel Energy Inc." **Prior (2025):** Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars)20242023Xcel Energy Inc. financing costs$(223)$(174)Xcel Energy Inc. taxes and other results (a)38 1 Total Xcel Energy Inc. and other costs$(185)$(173) Xcel Energy Inc. taxes and other results (a) (Diluted Earnings (Loss) Per Share)20242023Xcel Energy Inc. financing costs$(0.40)$(0.32)Xcel Energy Inc. taxes and other results (a)0.07 0.01 Total Xcel Energy Inc. and other costs$(0.33)$(0.31) Xcel Energy Inc. taxes and other results (a) (a)Amounts include gain from open market debt repurchases in 2024. Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. **Current (2026):** Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars)20252024Xcel Energy Inc. financing costs$(271)$(223)Xcel Energy Inc. other results (a)135 38 Total Xcel Energy Inc. and other$(136)$(185) Xcel Energy Inc. other results (a) (Diluted Earnings (Loss) Per Share)20252024Xcel Energy Inc. financing costs$(0.46)$(0.40)Xcel Energy Inc. other results (a)0.23 0.07 Total Xcel Energy Inc. and other costs$(0.23)$(0.33) Xcel Energy Inc. other results (a) (a)Amounts primarily include gains from debt repurchases, partially offset by taxes. Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. --- ## Modified: Non-Fuel Operating Expenses and Other Items **Key changes:** - Reworded sentence: "O&M Expenses - O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs." - Reworded sentence: "and its nonregulated businesses:(Millions of Dollars)20252024Xcel Energy Inc." - Reworded sentence: "Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and WGI." - Added sentence: "AFUDC, Equity and Debt - AFUDC increased $165 million in 2025, due to system investment." **Prior (2025):** O&M Expenses - O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses. Depreciation and Amortization - Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions. Other Income - Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation. Interest Charges - Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates. AFUDC, Equity and Debt - AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects. Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20242023Xcel Energy Inc. financing costs$(223)$(174)Xcel Energy Inc. taxes and other results (a)38 1 Total Xcel Energy Inc. and other costs$(185)$(173)(Diluted Earnings (Loss) Per Share)20242023Xcel Energy Inc. financing costs$(0.40)$(0.32)Xcel Energy Inc. taxes and other results (a)0.07 0.01 Total Xcel Energy Inc. and other costs$(0.33)$(0.31)(a)Amounts include gain from open market debt repurchases in 2024.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2023 Comparison with 2022 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2022 to Dec. 31, 2023 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb. 21, 2024. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. **Current (2026):** O&M Expenses - O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs. Depreciation and Amortization - Depreciation and amortization increased $209 million for the year, primarily related to system investment. Other Income - Other income increased $92 million for the year, primarily related to gains on debt repurchases. Interest Charges - Interest charges increased $213 million in 2025. The increase was largely due to higher long-term and short-term debt levels and higher interest rates. AFUDC, Equity and Debt - AFUDC increased $165 million in 2025, due to system investment.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20252024Xcel Energy Inc. financing costs$(271)$(223)Xcel Energy Inc. other results (a)135 38 Total Xcel Energy Inc. and other$(136)$(185)(Diluted Earnings (Loss) Per Share)20252024Xcel Energy Inc. financing costs$(0.46)$(0.40)Xcel Energy Inc. other results (a)0.23 0.07 Total Xcel Energy Inc. and other costs$(0.23)$(0.33)(a)Amounts primarily include gains from debt repurchases, partially offset by taxes.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2024 Comparison with 2023 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2023 to Dec. 31, 2024 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2024, which was filed with the SEC on Feb. 27, 2025. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and WGI. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. AFUDC, Equity and Debt - AFUDC increased $165 million in 2025, due to system investment. --- ## Modified: Results of Operations **Key changes:** - Reworded sentence: "31: Diluted Earnings (Loss) Per Share20252024NSP-Minnesota$1.53 $1.41 PSCo1.15 1.39 SPS0.67 0.70 NSP-Wisconsin0.27 0.24 Earnings from equity method investments - WYCO0.03 0.03 Regulated utility (a)3.65 3.76 Xcel Energy Inc." **Prior (2025):** Diluted EPS for Xcel Energy at Dec. 31: Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments - WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc. and Other(0.33)(0.31)GAAP Diluted EPS (a)3.44 3.21 Loss on Comanche Unit 3 litigation - 0.05 Workforce reduction expenses - 0.09 Sherco Unit 3 2011 outage refunds0.06 - Ongoing Diluted EPS (a)$3.50 $3.35 Regulated utility (a) GAAP Diluted EPS (a) Ongoing Diluted EPS (a) (a)Amounts may not add due to rounding. Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. **Current (2026):** Diluted EPS for Xcel Energy at Dec. 31: Diluted Earnings (Loss) Per Share20252024NSP-Minnesota$1.53 $1.41 PSCo1.15 1.39 SPS0.67 0.70 NSP-Wisconsin0.27 0.24 Earnings from equity method investments - WYCO0.03 0.03 Regulated utility (a)3.65 3.76 Xcel Energy Inc. and Other(0.23)(0.33)GAAP diluted EPS (a)$3.42 $3.44 Sherco Unit 3 2011 outage refunds - 0.06 Marshall Wildfire settlement0.38 - Ongoing diluted EPS (a)$3.80 $3.50 Regulated utility (a) GAAP diluted EPS (a) Ongoing diluted EPS (a) (a)Amounts may not add due to rounding. Xcel Energy's management believes that ongoing earnings reflects management's performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors. --- ## Modified: Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships. **Key changes:** - Added sentence: "The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment." - Added sentence: "As a result, we frequently need to access capital markets." - Added sentence: "Any disruption in capital markets could have a material impact on our ability to fund our operations." - Added sentence: "Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances." - Added sentence: "Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results." **Prior (2025):** Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings. **Current (2026):** Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota's nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract. Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings. --- ## Modified: Purchased Power and Transmission Service Providers **Key changes:** - Reworded sentence: "PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs." - Reworded sentence: "Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.SPSSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPUCTRetail electric operations, rates, services, construction of transmission or generation and other aspects of SPS' electric operations.The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities." - Reworded sentence: "DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAdvanced Metering System SurchargeRecovers costs incurred in deployment of the Advanced Metering System in Texas.Consulting Fee RiderRecovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.Distribution Cost Recovery FactorRecovers distribution costs not included in rates in Texas, including recovery of deferred Texas System Resiliency Plan costs.Electric Vehicle RiderRecovers costs of the Transportation Electrification Plan in New Mexico.Energy Efficiency Cost Recovery FactorRecovers costs for energy efficiency programs in Texas.Energy Efficiency RiderRecovers costs for energy efficiency programs in New Mexico.Fixed Fuel and Purchased Recovery FactorProvides for the over- or under-recovery of energy expenses in Texas." - Reworded sentence: "Grid Modernization RiderRecovers costs incurred in the implementation of Grid Modernization Components in New Mexico.Generation Cost Recovery RiderRecovers investments in a power generation facility outside of a base rate proceedingRenewable Portfolio StandardsRecovers deferred costs for renewable energy programs in New Mexico.Transmission Cost Recovery FactorRecovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.Wholesale Fuel and Purchased Energy Cost AdjustmentSPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC." **Prior (2025):** NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCo **Current (2026):** PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs. Purchased Power - PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo's long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost. Purchased Transmission Services - In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers. Wholesale and Commodity Marketing OperationsPSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to these hedging activities. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.SPSSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPUCTRetail electric operations, rates, services, construction of transmission or generation and other aspects of SPS' electric operations.The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities' rate setting decisions are subject to PUCT review. NMPRCRetail electric operations, retail rates and services and the construction of transmission or generation.Reviews Integrated Resource Plans for meeting future energy needs.FERCWholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.SPP RTO and SPP Integrated and Wholesale MarketsSPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets. SPS is authorized to make wholesale electric sales at market-based prices. DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAdvanced Metering System SurchargeRecovers costs incurred in deployment of the Advanced Metering System in Texas.Consulting Fee RiderRecovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.Distribution Cost Recovery FactorRecovers distribution costs not included in rates in Texas, including recovery of deferred Texas System Resiliency Plan costs.Electric Vehicle RiderRecovers costs of the Transportation Electrification Plan in New Mexico.Energy Efficiency Cost Recovery FactorRecovers costs for energy efficiency programs in Texas.Energy Efficiency RiderRecovers costs for energy efficiency programs in New Mexico.Fixed Fuel and Purchased Recovery FactorProvides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility's annual fuel and purchased energy costs on a rolling 12-month basis if this condition is expected to continue.Fuel and Purchased Power Cost Adjustment ClauseAdjusts monthly to recover actual fuel and purchased power costs in New Mexico. Grid Modernization RiderRecovers costs incurred in the implementation of Grid Modernization Components in New Mexico.Generation Cost Recovery RiderRecovers investments in a power generation facility outside of a base rate proceedingRenewable Portfolio StandardsRecovers deferred costs for renewable energy programs in New Mexico.Transmission Cost Recovery FactorRecovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.Wholesale Fuel and Purchased Energy Cost AdjustmentSPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs. --- ## Modified: Pending and Recently Concluded Regulatory Proceedings **Key changes:** - Reworded sentence: "2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%)." - Reworded sentence: "The MPUC also approved a continuation of the sales true-up mechanism." - Reworded sentence: "1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%." - Reworded sentence: "Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No." - Reworded sentence: "NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations." **Prior (2025):** 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). **Current (2026):** 2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. 29 29 29 Table of Contents Table of Contents In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026. 2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026. The procedural schedule is as follows: •Intervenor direct testimony: March 20, 2026 •Rebuttal testimony: April 14, 2026 •Evidentiary Hearing: April 28-30, 2026 A SDPUC decision is expected in the first half of 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. --- ## Modified: Derivatives, Risk Management and Market Risk **Key changes:** - Removed sentence: "38 38 38 Table of Contents Table of Contents Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund." - Removed sentence: "Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations." - Removed sentence: "Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities." - Removed sentence: "Commodity price risk is also managed through the use of financial derivative instruments." - Removed sentence: "Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives." **Prior (2025):** We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. 38 38 38 Table of Contents Table of Contents Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2024:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(16)$(19)$(4)$ - $(39)NSP-Minnesota (b)3 10 (4)2 11 PSCo (a)1 5 - - 6 $(12)$(4)$(8)$2 $(22)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $20 $ - $20 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20242023Fair value of commodity trading net contracts outstanding at Jan. 1$1 $(10)Contracts realized or settled during the period - (2)Commodity trading contract additions and changes during the period(3)13 Fair value of commodity trading net contracts outstanding at Dec. 31$(2)$1 A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2024 and $4 million at Dec. 31, 2023.The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2024$ - $ - $1 $ - 2023 - - 1 - Nuclear Fuel Supply - NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2024:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(16)$(19)$(4)$ - $(39)NSP-Minnesota (b)3 10 (4)2 11 PSCo (a)1 5 - - 6 $(12)$(4)$(8)$2 $(22)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $ - $20 $ - $20 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20242023Fair value of commodity trading net contracts outstanding at Jan. 1$1 $(10)Contracts realized or settled during the period - (2)Commodity trading contract additions and changes during the period(3)13 Fair value of commodity trading net contracts outstanding at Dec. 31$(2)$1 A 10% increase and 10% decrease in forward market prices for Xcel Energy's commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2024 and $4 million at Dec. 31, 2023.The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2024: Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(16)$(19)$(4)$ - $(39)NSP-Minnesota (b)3 10 (4)2 11 PSCo (a)1 5 - - 6 $(12)$(4)$(8)$2 $(22) NSP-Minnesota (a) NSP-Minnesota (b) PSCo (a) **Current (2026):** We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2025: Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(10)$(15)$(3)$(1)$(29)NSP-Minnesota (b)1 (2) - (4)(5)PSCo (a)(1) - - - (1)$(10)$(17)$(3)$(5)$(35) NSP-Minnesota (a) NSP-Minnesota (b) PSCo (a) --- ## Modified: Financing Cash Flows **Key changes:** - Reworded sentence: "31Cash provided by financing activities - 2024$2,837 Components of change - 2025 vs." **Prior (2025):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2023$617 Components of change - 2024 vs. 2023Higher long-term debt issuances, net of repayments1,512 Higher proceeds from issuance of common stock847 Higher dividends paid to shareholders(83)Other financing activities(56)Cash provided by financing activities - 2024$2,837 Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023. The increase was largely related to additional debt and common stock issuances to fund capital investment. See Note 5 to the consolidated financial statements for further information. **Current (2026):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2024$2,837 Components of change - 2025 vs. 2024Higher long-term debt issuances, net of repayments1,059 Higher net short-term debt proceeds945 Higher proceeds from issuance of common stock2,232 Other financing activities(92)Cash provided by financing activities - 2025$6,981 Net cash provided by financing activities increased by $4,144 million for 2025 as compared to 2024. The increase was largely related to additional debt and common stock issuances to fund capital investment. See Note 5 to the consolidated financial statements for further information. --- ## Modified: We must rely on cash from our subsidiaries to make dividend payments. **Key changes:** - Removed sentence: "Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates." - Removed sentence: "Changes to federal tax law may benefit or adversely affect our earnings and customer costs." - Removed sentence: "Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources." - Removed sentence: "If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues." - Removed sentence: "In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices." **Prior (2025):** Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary's ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.Macroeconomic RisksEconomic conditions impact our business.Xcel Energy's operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers' ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. **Current (2026):** Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary's ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. --- ## Modified: 2025 Comparison with 2024 **Key changes:** - Reworded sentence: "Xcel Energy - GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024." - Reworded sentence: "NSP-Minnesota - GAAP earnings increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024." - Reworded sentence: "The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels.Changes in Diluted EPSComponents significantly contributing to changes in 2025 EPS compared with 2024:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec." - Removed sentence: "As a result, weather deviations from normal levels can affect Xcel Energy's financial performance." - Removed sentence: "However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction." **Prior (2025):** Xcel Energy - GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota - GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges. PSCo - GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges. SPS - GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth. NSP-Wisconsin - GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation. Xcel Energy Inc. and Other - Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.Changes in Diluted EPSComponents significantly contributing to changes in 2024 EPS compared with 2023:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS - 2023$3.21 Components of change - 2024 vs. 2023Electric regulatory rate outcomes and riders0.73 Higher other income, net0.16 Natural gas regulatory rate outcomes and riders0.14 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Higher depreciation and amortization(0.40)Interest charges, net of AFUDC - debt(0.24)Higher O&M expenses(0.13)Sherco Unit 3 2011 outage refunds(0.06)Other, net(0.11)GAAP diluted EPS - 2024$3.44 Sherco Unit 3 2011 outage refunds0.06 Ongoing diluted EPS - 2024$3.50 ROE for Xcel Energy and its utility subsidiaries:20242023ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.07 %9.46 %8.82 %9.11 %PSCo7.63 7.63 7.32 7.77 SPS9.57 9.57 9.80 9.98 NSP-Wisconsin8.98 8.98 10.38 10.67 Utility Subsidiaries8.55 8.69 8.45 8.79 Xcel Energy10.42 10.61 10.33 10.79 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.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. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. 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 decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases. **Current (2026):** Xcel Energy - GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024. The change in ongoing EPS was driven by increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota - GAAP earnings increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024. Ongoing earnings increased due to higher recovery of electric infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges. PSCo - GAAP earnings decreased $0.24 per share and ongoing earnings increased $0.14 per share for 2025 (difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Non-GAAP Financial Measures for reconciliation from GAAP to ongoing earnings). Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M charges. SPS - GAAP and ongoing earnings decreased $0.03 per share for 2025 . The decrease was driven by increased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher recovery of electric infrastructure investments. NSP-Wisconsin - GAAP and ongoing earnings increased $0.03 per share for 2025. The increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and O&M expenses. Xcel Energy Inc. and Other - Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels.Changes in Diluted EPSComponents significantly contributing to changes in 2025 EPS compared with 2024:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS - 2024$3.44 Components of change - 2025 vs. 2024Higher electric revenues1.27 Higher natural gas revenues0.29 Higher AFUDC equity & debt0.27 Marshall Wildfire settlement(0.38)Higher interest charges(0.28)Higher depreciation and amortization(0.28)Higher O&M expenses(0.25)Higher electric fuel and purchased power (a)(0.23)Common equity financing(0.18)Higher costs of natural gas sold and transported (a)(0.12)Other, net(0.13)GAAP diluted EPS - 2025$3.42 Marshall Wildfire settlement0.38 Ongoing diluted EPS - 2025$3.80 (a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.ROE for Xcel Energy and its utility subsidiaries:20252024ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.19 %9.19 %9.07 %9.46 %PSCo5.66 7.55 7.63 7.63 SPS8.70 8.70 9.57 9.57 NSP-Wisconsin9.09 9.09 8.98 8.98 Utility Subsidiaries7.60 8.40 8.55 8.69 Xcel Energy9.36 10.38 10.42 10.61 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.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. Xcel Energy Inc. and Other - Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels. --- ## Modified: Material Cash Requirements and Other Commitments **Key changes:** - Reworded sentence: "31, 2025)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$57,743 $1,937 $4,766 $3,793 $47,247 Finance lease obligations2,183 112 225 232 1,614 Operating leases obligations (a)1,259 152 250 226 631 Unconditional purchase obligations (b) 4,264 1,264 1,097 520 1,383 Short-term debt1,550 1,550 - - - Other587 574 13 - - Total contractual cash obligations$67,586 $5,589 $6,351 $4,771 $50,875 Operating leases obligations (a) Unconditional purchase obligations (b) (a)Included in operating lease obligations are $121 million, $170 million, $156 million and $185 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases." - Reworded sentence: "Capital Expenditures - Base capital expenditures for Xcel Energy for 2026 through 2030: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2025202620272028202920302026 - 2030 TotalNSP-Minnesota$3,380 $3,740 $4,870 $4,210 $3,660 $3,650 $20,130 SPS1,610 3,050 5,120 5,350 3,240 2,270 19,030 PSCo5,440 5,980 3,940 2,960 1,760 2,960 17,600 NSP-Wisconsin710 910 1,210 760 570 580 4,030 Other (a)470 110 (10)(630)(210)(50)(790)Total base capital expenditures$11,610 $13,790 $15,130 $12,650 $9,020 $9,410 $60,000 Other (a) (a)Other category includes intercompany transfers for equipment with long lead times." - Reworded sentence: "Financing for Capital Expenditures through 2030 - Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes." - Reworded sentence: "31, 2024Fair value of pension assets$2,690 $2,504 Projected pension obligation (a)2,820 2,752 Funded status$(130)$(248)(a)Excludes non-qualified plan of $13 million at both Dec." - Reworded sentence: "Authorized levels for these commercial paper programs are:•$2 billion for Xcel Energy Inc.•$1.2 billion for PSCo.•$800 million for NSP-Minnesota.•$600 million for SPS.•$150 million for NSP-Wisconsin." **Prior (2025):** Payments Due by Period (as of Dec. 31, 2024)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$50,915 $2,292 $3,316 $3,846 $41,461 Finance lease obligations208 10 17 16 165 Operating leases obligations (a)1,355 271 432 215 437 Unconditional purchase obligations (b) (c)3,755 1,432 1,207 432 684 Other long-term obligations, including current portion (d)85 20 36 29 - Other short-term obligations632 632 - - - Short-term debt695 695 - - - Total contractual cash obligations$57,645 $5,352 $5,008 $4,538 $42,747 Operating leases obligations (a) Unconditional purchase obligations (b) (c) Other long-term obligations, including current portion (d) (a)Included in operating lease obligations are $240 million, $372 million, $166 million and $199 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases. (b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms. (c)Amounts exclude approximately $1 billion of incremental payments related to SPS' renegotiation and extension of a non-lease PPA that received PUCT approval in February 2025. The extension to 2040 will result in annual payments of approximately $65 million to $80 million commencing in 2025. (d)Primarily consists of contracts for information technology services. Capital Expenditures - Base capital expenditures for Xcel Energy for 2025 through 2029: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2024202520262027202820292025 - 2029 TotalPSCo$3,180 $5,820 $5,190 $3,940 $3,780 $3,550 $22,280 NSP-Minnesota2,830 3,240 2,500 2,830 2,080 2,570 13,220 SPS1,100 1,400 1,540 1,280 1,040 1,040 6,300 NSP-Wisconsin560 640 650 690 660 670 3,310 Other (a)(20)(100)(40)10 10 10 (110)Total base capital expenditures$7,650 $11,000 $9,840 $8,750 $7,570 $7,840 $45,000 Other (a) (a)Other category includes intercompany transfers for safe harbor wind turbines. ActualBase Capital Forecast (Millions of Dollars)By Function2024202520262027202820292025 - 2029 TotalElectric distribution$2,220 $2,570 $3,000 $3,400 $3,320 $3,540 $15,830 Electric transmission1,720 2,260 2,860 2,740 2,390 2,310 12,560 Renewables1,130 3,360 1,400 260 - - 5,020 Electric generation960 1,210 1,150 910 580 620 4,470 Natural gas780 800 680 690 630 620 3,420 Other840 800 750 750 650 750 3,700 Total base capital expenditures$7,650 $11,000 $9,840 $8,750 $7,570 $7,840 $45,000 The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.Financing for Capital Expenditures through 2029 - 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. The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2029 - 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. Financing for Capital Expenditures through 2029 - 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. 41 41 41 Table of Contents Table of Contents Current estimated financing plans of Xcel Energy for 2025 through 2029 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$25,320 New debt (b)15,180 Equity through the DRIP and benefit program500 Other equity4,000 Base capital expenditures 2025 - 2029$45,000 Maturing debt$3,730 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253)(a)Excludes non-qualified plan of $13 million and $12 million at Dec. 31, 2024 and 2023, respectively.Pension Assumptions20242023Discount rate5.88 %5.49 %Expected long-term rate of return7.13 6.93 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - As of Feb. 24, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $660 $840 $25 $865 PSCo700 101 599 10 609 NSP-Minnesota700 375 325 7 332 SPS500 255 245 7 252 NSP-Wisconsin150 27 123 3 126 Total$3,550 $1,418 $2,132 $52 $2,184 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.Long-Term Borrowings, Equity Issuances and Other Financing Instruments - Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. Current estimated financing plans of Xcel Energy for 2025 through 2029 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$25,320 New debt (b)15,180 Equity through the DRIP and benefit program500 Other equity4,000 Base capital expenditures 2025 - 2029$45,000 Maturing debt$3,730 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253)(a)Excludes non-qualified plan of $13 million and $12 million at Dec. 31, 2024 and 2023, respectively.Pension Assumptions20242023Discount rate5.88 %5.49 %Expected long-term rate of return7.13 6.93 Current estimated financing plans of Xcel Energy for 2025 through 2029 (includes the impact of tax credit transferability): (Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$25,320 New debt (b)15,180 Equity through the DRIP and benefit program500 Other equity4,000 Base capital expenditures 2025 - 2029$45,000 Maturing debt$3,730 Cash from operations (a) New debt (b) (a)Net of dividends and pension funding. (b)Reflects a combination of short and long-term debt; net of refinancing. **Current (2026):** Payments Due by Period (as of Dec. 31, 2025)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$57,743 $1,937 $4,766 $3,793 $47,247 Finance lease obligations2,183 112 225 232 1,614 Operating leases obligations (a)1,259 152 250 226 631 Unconditional purchase obligations (b) 4,264 1,264 1,097 520 1,383 Short-term debt1,550 1,550 - - - Other587 574 13 - - Total contractual cash obligations$67,586 $5,589 $6,351 $4,771 $50,875 Operating leases obligations (a) Unconditional purchase obligations (b) (a)Included in operating lease obligations are $121 million, $170 million, $156 million and $185 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases. (b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms. Capital Expenditures - Base capital expenditures for Xcel Energy for 2026 through 2030: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2025202620272028202920302026 - 2030 TotalNSP-Minnesota$3,380 $3,740 $4,870 $4,210 $3,660 $3,650 $20,130 SPS1,610 3,050 5,120 5,350 3,240 2,270 19,030 PSCo5,440 5,980 3,940 2,960 1,760 2,960 17,600 NSP-Wisconsin710 910 1,210 760 570 580 4,030 Other (a)470 110 (10)(630)(210)(50)(790)Total base capital expenditures$11,610 $13,790 $15,130 $12,650 $9,020 $9,410 $60,000 Other (a) (a)Other category includes intercompany transfers for equipment with long lead times. 41 41 41 Table of Contents Table of Contents ActualBase Capital Forecast (Millions of Dollars)By Function2025202620272028202920302026 - 2030 TotalElectric transmission$2,250 $3,060 $2,930 $2,890 $3,190 $3,370 $15,440 Renewables3,190 3,560 4,620 3,380 1,150 1,210 13,920 Electric distribution2,690 2,920 3,250 2,930 1,680 2,930 13,710 Electric generation1,250 2,220 2,420 2,500 1,810 590 9,540 Natural gas740 860 830 700 650 680 3,720 Other1,490 1,170 1,080 250 540 630 3,670 Total base capital expenditures$11,610 $13,790 $15,130 $12,650 $9,020 $9,410 $60,000 The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt.Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2030 - Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2026 through 2030 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$30,180 New debt (b)22,820 Equity issuances (c)7,000 Base capital expenditures 2026 - 2030$60,000 Maturing debt$3,580 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2026, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.0%.Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024Fair value of pension assets$2,690 $2,504 Projected pension obligation (a)2,820 2,752 Funded status$(130)$(248)(a)Excludes non-qualified plan of $13 million at both Dec. 31, 2025 and 2024.Pension Assumptions20252024Discount rate for year-end valuation5.78 %5.88 %Expected long-term rate of return7.13 7.13 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$2 billion for Xcel Energy Inc.•$1.2 billion for PSCo.•$800 million for NSP-Minnesota.•$600 million for SPS.•$150 million for NSP-Wisconsin. The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt.Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2030 - Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2026 through 2030 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$30,180 New debt (b)22,820 Equity issuances (c)7,000 Base capital expenditures 2026 - 2030$60,000 Maturing debt$3,580 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2026, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.0%. The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy's capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2030 - Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2026 through 2030 (includes the impact of tax credit transferability): (Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$30,180 New debt (b)22,820 Equity issuances (c)7,000 Base capital expenditures 2026 - 2030$60,000 Maturing debt$3,580 Cash from operations (a) New debt (b) Equity issuances (c) (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. --- ## Modified: Electric Revenues **Key changes:** - Reworded sentence: "Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality." - Reworded sentence: "27 27 27 Table of Contents Table of Contents (Millions of Dollars)2025 vs." - Reworded sentence: "Electric fuel and purchased power expenses increased $173 million in 2025." - Reworded sentence: "As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.Natural gas sold and transported increased $90 million in 2025." - Reworded sentence: "and its nonregulated businesses:(Millions of Dollars)20252024Xcel Energy Inc." **Prior (2025):** Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes. (Millions of Dollars)2024 vs. 2023Recovery of lower cost of electric fuel and purchase power(479)PTCs flowed back to customers (offset by lower ETR)(302)Wholesale generation revenues(96)Sherco Unit 3 2011 outage refunds(47)Regulatory rate outcomes (MN, CO, TX, and NM)372 Non-fuel riders169 Conservation and demand side management (offset in expense)102 Estimated impact of weather (net of sales true-up)24 Other, net(42)Total decrease$(299) 27 27 27 Table of Contents Table of Contents Natural Gas RevenuesNatural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of natural gas$(496)Estimated impact of weather (net of decoupling)(35)Retail sales decline (net of decoupling)(1)Regulatory rate outcomes (MN, WI, CO, and ND)91 Infrastructure and integrity riders8 Other, net18 Total decrease$(415)Electric Fuel and Purchased Power - Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of 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 $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes.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 $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes.Non-Fuel Operating Expenses and Other ItemsO&M Expenses - O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses.Depreciation and Amortization - Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions. Other Income - Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.Interest Charges - Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.AFUDC, Equity and Debt - AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20242023Xcel Energy Inc. financing costs$(223)$(174)Xcel Energy Inc. taxes and other results (a)38 1 Total Xcel Energy Inc. and other costs$(185)$(173)(Diluted Earnings (Loss) Per Share)20242023Xcel Energy Inc. financing costs$(0.40)$(0.32)Xcel Energy Inc. taxes and other results (a)0.07 0.01 Total Xcel Energy Inc. and other costs$(0.33)$(0.31)(a)Amounts include gain from open market debt repurchases in 2024.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2023 Comparison with 2022 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2022 to Dec. 31, 2023 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb. 21, 2024. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. Natural Gas RevenuesNatural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of natural gas$(496)Estimated impact of weather (net of decoupling)(35)Retail sales decline (net of decoupling)(1)Regulatory rate outcomes (MN, WI, CO, and ND)91 Infrastructure and integrity riders8 Other, net18 Total decrease$(415)Electric Fuel and Purchased Power - Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of 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 $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes.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 $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes.Non-Fuel Operating Expenses and Other ItemsO&M Expenses - O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses.Depreciation and Amortization - Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions. Other Income - Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.Interest Charges - Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.AFUDC, Equity and Debt - AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects. **Current (2026):** Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes. 27 27 27 Table of Contents Table of Contents (Millions of Dollars)2025 vs. 2024Non-fuel riders$250 Recovery of higher cost of electric fuel and purchased power214 PTCs flowed back to customers (offset by lower ETR)172 Regulatory rate outcomes (MN, ND)116 Sales and demand 97 Transmission revenues79 Sherco Unit 3 2011 outage refunds47 Estimated impact of weather(39)Conservation and demand side management (offset in expense)(38)Other, net115 Total increase$1,013 Natural Gas RevenuesNatural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.(Millions of Dollars)2025 vs. 2024Recovery of higher cost of natural gas$92 Regulatory rate outcomes (CO)84 Conservation revenue (offset in expense)47 Estimated impact of weather (net of decoupling)11 Retail sales decline (net of decoupling)(13)Other, net1 Total increase$222 Electric Fuel and Purchased Power - Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses increased $173 million in 2025. The increase is primarily due to increased commodity prices and transmission expense.Cost of Natural Gas Sold and Transported - Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.Natural gas sold and transported increased $90 million in 2025. The increase is primarily due to increased commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.Non-Fuel Operating Expenses and Other ItemsO&M Expenses - O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs.Depreciation and Amortization - Depreciation and amortization increased $209 million for the year, primarily related to system investment.Other Income - Other income increased $92 million for the year, primarily related to gains on debt repurchases.Interest Charges - Interest charges increased $213 million in 2025. The increase was largely due to higher long-term and short-term debt levels and higher interest rates.AFUDC, Equity and Debt - AFUDC increased $165 million in 2025, due to system investment.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20252024Xcel Energy Inc. financing costs$(271)$(223)Xcel Energy Inc. other results (a)135 38 Total Xcel Energy Inc. and other$(136)$(185)(Diluted Earnings (Loss) Per Share)20252024Xcel Energy Inc. financing costs$(0.46)$(0.40)Xcel Energy Inc. other results (a)0.23 0.07 Total Xcel Energy Inc. and other costs$(0.23)$(0.33)(a)Amounts primarily include gains from debt repurchases, partially offset by taxes.Xcel Energy Inc.'s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2024 Comparison with 2023 A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2023 to Dec. 31, 2024 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2024, which was filed with the SEC on Feb. 27, 2025. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'s utility subsidiaries and WGI. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy's results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. (Millions of Dollars)2025 vs. 2024Non-fuel riders$250 Recovery of higher cost of electric fuel and purchased power214 PTCs flowed back to customers (offset by lower ETR)172 Regulatory rate outcomes (MN, ND)116 Sales and demand 97 Transmission revenues79 Sherco Unit 3 2011 outage refunds47 Estimated impact of weather(39)Conservation and demand side management (offset in expense)(38)Other, net115 Total increase$1,013 Natural Gas RevenuesNatural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.(Millions of Dollars)2025 vs. 2024Recovery of higher cost of natural gas$92 Regulatory rate outcomes (CO)84 Conservation revenue (offset in expense)47 Estimated impact of weather (net of decoupling)11 Retail sales decline (net of decoupling)(13)Other, net1 Total increase$222 Electric Fuel and Purchased Power - Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses increased $173 million in 2025. The increase is primarily due to increased commodity prices and transmission expense.Cost of Natural Gas Sold and Transported - Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.Natural gas sold and transported increased $90 million in 2025. The increase is primarily due to increased commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.Non-Fuel Operating Expenses and Other ItemsO&M Expenses - O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs.Depreciation and Amortization - Depreciation and amortization increased $209 million for the year, primarily related to system investment.Other Income - Other income increased $92 million for the year, primarily related to gains on debt repurchases.Interest Charges - Interest charges increased $213 million in 2025. The increase was largely due to higher long-term and short-term debt levels and higher interest rates. (Millions of Dollars)2025 vs. 2024Non-fuel riders$250 Recovery of higher cost of electric fuel and purchased power214 PTCs flowed back to customers (offset by lower ETR)172 Regulatory rate outcomes (MN, ND)116 Sales and demand 97 Transmission revenues79 Sherco Unit 3 2011 outage refunds47 Estimated impact of weather(39)Conservation and demand side management (offset in expense)(38)Other, net115 Total increase$1,013 Sales and demand --- ## Modified: (Millions of Dollars)Year Ended Dec. 31AverageHighLow2025$ - $ - $1 $ - 2024 - - 1 - **Key changes:** - Removed sentence: "Nuclear Fuel Supply - NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States." - Removed sentence: "In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law." - Removed sentence: "As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received." - Reworded sentence: "A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $17 million and $7 million in 2025 and 2024, respectively." - Reworded sentence: "Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided." **Prior (2025):** Nuclear Fuel Supply - NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives. A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs. The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million. 39 39 39 Table of Contents Table of Contents Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2023$5,327 Components of change - 2024 vs. 2023Higher net income165 Non-cash transactions222 Changes in deferred taxes284 Changes in working capital (783)Changes in net regulatory and other assets and liabilities(574)Cash provided by operating activities - 2024$4,641 Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2023$(5,926)Components of change - 2024 vs. 2023Increased capital expenditures(1,510)Other investing activities8 Cash used in investing activities - 2024$(7,428)Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2023$617 Components of change - 2024 vs. 2023Higher long-term debt issuances, net of repayments1,512 Higher proceeds from issuance of common stock847 Higher dividends paid to shareholders(83)Other financing activities(56)Cash provided by financing activities - 2024$2,837 Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023. The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information.Capital RequirementsXcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy's financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation. Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2023$5,327 Components of change - 2024 vs. 2023Higher net income165 Non-cash transactions222 Changes in deferred taxes284 Changes in working capital (783)Changes in net regulatory and other assets and liabilities(574)Cash provided by operating activities - 2024$4,641 Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers. Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. **Current (2026):** Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives. A 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $17 million and $7 million in 2025 and 2024, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota's nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs. The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy's ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan's funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Xcel Energy's subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support.Xcel Energy is also subject to credit risk for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.At Dec. 31, 2025, a 10% increase or decrease in commodity prices would have resulted in an increase or decrease in credit exposure of $27 million. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $25 million.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2024$4,641 Components of change - 2025 vs. 2024Higher net income82 Non-cash transactions121 Changes in deferred taxes189 Changes in working capital (304)Changes in net regulatory and other assets and liabilities(646)Cash provided by operating activities - 2025$4,083 Net cash provided by operating activities decreased by $558 million for 2025 as compared to 2024. The decrease was largely due to the payment of the Marshall Wildfire settlement and timing of regulatory recovery, including deferred fuel costs. Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. Xcel Energy's subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support. Xcel Energy is also subject to credit risk for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. At Dec. 31, 2025, a 10% increase or decrease in commodity prices would have resulted in an increase or decrease in credit exposure of $27 million. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $25 million. --- ## Modified: 2024 Comparison with 2023 **Key changes:** - Reworded sentence: "31, 2024 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2024, which was filed with the SEC on Feb." **Prior (2025):** A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2022 to Dec. 31, 2023 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb. 21, 2024. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. **Current (2026):** A discussion of changes in Xcel Energy's results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2023 to Dec. 31, 2024 can be found in Part II, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year 2024, which was filed with the SEC on Feb. 27, 2025. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. --- ## Modified: Off-Balance Sheet Arrangements **Key changes:** - Reworded sentence: "In February 2026, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.0%." - Reworded sentence: "31, 2024Fair value of pension assets$2,690 $2,504 Projected pension obligation (a)2,820 2,752 Funded status$(130)$(248) Projected pension obligation (a) (a)Excludes non-qualified plan of $13 million at both Dec." **Prior (2025):** Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%. Xcel Energy's dividend policy balances the following: •Projected cash generation. •Projected capital investment. •A reasonable rate of return on shareholder investment. •The impact on Xcel Energy's capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See Note 5 to the consolidated financial statements for further information. Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions: (Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253) Projected pension obligation (a) (a)Excludes non-qualified plan of $13 million and $12 million at Dec. 31, 2024 and 2023, respectively. Pension Assumptions20242023Discount rate5.88 %5.49 %Expected long-term rate of return7.13 6.93 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - As of Feb. 24, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $660 $840 $25 $865 PSCo700 101 599 10 609 NSP-Minnesota700 375 325 7 332 SPS500 255 245 7 252 NSP-Wisconsin150 27 123 3 126 Total$3,550 $1,418 $2,132 $52 $2,184 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.Long-Term Borrowings, Equity Issuances and Other Financing Instruments - Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. **Current (2026):** Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2026, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.0%. Xcel Energy's dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy's capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024Fair value of pension assets$2,690 $2,504 Projected pension obligation (a)2,820 2,752 Funded status$(130)$(248)(a)Excludes non-qualified plan of $13 million at both Dec. 31, 2025 and 2024.Pension Assumptions20252024Discount rate for year-end valuation5.78 %5.88 %Expected long-term rate of return7.13 7.13 Capital SourcesShort-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$2 billion for Xcel Energy Inc.•$1.2 billion for PSCo.•$800 million for NSP-Minnesota.•$600 million for SPS.•$150 million for NSP-Wisconsin. Xcel Energy's dividend policy balances the following: •Projected cash generation. •Projected capital investment. •A reasonable rate of return on shareholder investment. •The impact on Xcel Energy's capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See Note 5 to the consolidated financial statements for further information. Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions: (Millions of Dollars)Dec. 31, 2025Dec. 31, 2024Fair value of pension assets$2,690 $2,504 Projected pension obligation (a)2,820 2,752 Funded status$(130)$(248) Projected pension obligation (a) (a)Excludes non-qualified plan of $13 million at both Dec. 31, 2025 and 2024. Pension Assumptions20252024Discount rate for year-end valuation5.78 %5.88 %Expected long-term rate of return7.13 7.13 --- ## Modified: Annual weather-normalized and leap year adjusted electric sales growth (decline) **Key changes:** - Reworded sentence: "•NSP-Minnesota - Residential sales increased due to customer growth (1.1%) and use per customer (0.4%)." **Prior (2025):** •NSP-Minnesota - Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector. •PSCo - Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining. •SPS - Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining. •NSP-Wisconsin - Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors. **Current (2026):** •NSP-Minnesota - Residential sales increased due to customer growth (1.1%) and use per customer (0.4%). The decrease in C&I sales was due to lower use per customer. •PSCo - Residential sales increased due to customer growth (1.1%) and use per customer (0.6%). The increase in C&I sales was due to higher use per customer, particularly in the information and energy sectors. •SPS - Residential sales increased due to increased use per customer (3.6%) and customer growth (0.7%). The increase in C&I sales was due to higher use per customer, primarily driven by the energy sector. •NSP-Wisconsin - Residential sales increased due to increased use per customer (1.1%) and customer growth (0.9%). The increase in C&I sales was due to customer growth. --- ## Modified: Failure to attract and retain a qualified workforce could have an adverse effect on operations. **Key changes:** - Added sentence: "National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work." - Added sentence: "Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines." - Added sentence: "Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution.Actions of our employees, directors, third-party contractors or suppliers could expose us to reputational risks.We could suffer negative impacts to our reputation as a result of actual or perceived fraud, misconduct, legal or regulatory violations, violations of corporate policies, inappropriate use of social media, or other actions by our employees, directors, third-party contractors or suppliers." - Added sentence: "Reputational damage could have a material adverse effect and could result in negative customer perception, litigation and increased regulatory oversight.Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello." - Added sentence: "Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S." **Prior (2025):** The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows. Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs. **Current (2026):** The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows. Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution.Actions of our employees, directors, third-party contractors or suppliers could expose us to reputational risks.We could suffer negative impacts to our reputation as a result of actual or perceived fraud, misconduct, legal or regulatory violations, violations of corporate policies, inappropriate use of social media, or other actions by our employees, directors, third-party contractors or suppliers. Reputational damage could have a material adverse effect and could result in negative customer perception, litigation and increased regulatory oversight.Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota's nuclear operations. Compliance with the INPO's recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota's compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs. --- ## Modified: Capital Sources **Key changes:** - Reworded sentence: "Authorized levels for these commercial paper programs are: •$2 billion for Xcel Energy Inc." - Added sentence: "42 42 42 Table of Contents Table of Contents See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - As of Feb." - Added sentence: "23, 2026, Xcel Energy Inc." - Added sentence: "and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$2,000 $790 $1,210 $21 $1,231 PSCo1,200 308 892 9 901 NSP-Minnesota800 329 471 3 474 SPS600 213 387 11 398 NSP-Wisconsin150 - 150 2 152 Total$4,750 $1,640 $3,110 $46 $3,156 Term Loan (c)1,500 750 750 - 750 (a)Credit facilities expire in December 2029.(b)Includes outstanding commercial paper and letters of credit.(c)Xcel Energy Inc.'s $1.5 billion term loan (entered into in January 2026) matures in January 2027.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods." - Added sentence: "NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year." **Prior (2025):** Short-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments. Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are: •$1.50 billion for Xcel Energy Inc. •$700 million for PSCo. •$700 million for NSP-Minnesota. •$500 million for SPS. •$150 million for NSP-Wisconsin. See Note 5 to the consolidated financial statements for further information. Credit Facility Agreements - As of Feb. 24, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $660 $840 $25 $865 PSCo700 101 599 10 609 NSP-Minnesota700 375 325 7 332 SPS500 255 245 7 252 NSP-Wisconsin150 27 123 3 126 Total$3,550 $1,418 $2,132 $52 $2,184 Facility (a) Drawn (b) (a)Credit facilities expire in September 2027. (b)Includes outstanding commercial paper and letters of credit. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval. Long-Term Borrowings, Equity Issuances and Other Financing Instruments - Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. 42 42 42 Table of Contents Table of Contents Planned Financing Activity - Xcel Energy's 2025 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Expected TenorAnticipated TimingXcel Energy Inc.Senior Unsecured Notes$1,000 10 YearFirst QuarterPSCoFirst Mortgage Bonds2,000 10 Year & 30 YearSecond & Third QuarterNSP-MinnesotaFirst Mortgage Bonds1,100 10 Year & 30 YearFirst & Third QuarterSPSFirst Mortgage Bonds45030 YearSecond QuarterNSP-WisconsinFirst Mortgage Bonds25030 YearSecond QuarterSee Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2025 Earnings Guidance - Xcel Energy's 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)Key assumptions as compared with 2024 actual levels unless noted:•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.•Normal weather patterns for the year.•Weather-normalized retail electric sales are projected to increase ~3%.•Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs).•O&M expenses are projected to increase ~3%.•Depreciation expense is projected to increase approximately $210 million to $220 million.•Property taxes are projected to increase $55 million to $65 million. •Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income. •AFUDC - equity is projected to increase $110 million to $120 million.(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management's view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:• Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).• Deliver annual dividend increases of 4% to 6%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Planned Financing Activity - Xcel Energy's 2025 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Expected TenorAnticipated TimingXcel Energy Inc.Senior Unsecured Notes$1,000 10 YearFirst QuarterPSCoFirst Mortgage Bonds2,000 10 Year & 30 YearSecond & Third QuarterNSP-MinnesotaFirst Mortgage Bonds1,100 10 Year & 30 YearFirst & Third QuarterSPSFirst Mortgage Bonds45030 YearSecond QuarterNSP-WisconsinFirst Mortgage Bonds25030 YearSecond QuarterSee Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2025 Earnings Guidance - Xcel Energy's 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)Key assumptions as compared with 2024 actual levels unless noted:•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.•Normal weather patterns for the year.•Weather-normalized retail electric sales are projected to increase ~3%.•Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs).•O&M expenses are projected to increase ~3%.•Depreciation expense is projected to increase approximately $210 million to $220 million.•Property taxes are projected to increase $55 million to $65 million. •Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income. •AFUDC - equity is projected to increase $110 million to $120 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. Planned Financing Activity - Xcel Energy's 2025 financing plans reflect the following: IssuerSecurityAmount (Millions of Dollars)Expected TenorAnticipated TimingXcel Energy Inc.Senior Unsecured Notes$1,000 10 YearFirst QuarterPSCoFirst Mortgage Bonds2,000 10 Year & 30 YearSecond & Third QuarterNSP-MinnesotaFirst Mortgage Bonds1,100 10 Year & 30 YearFirst & Third QuarterSPSFirst Mortgage Bonds45030 YearSecond QuarterNSP-WisconsinFirst Mortgage Bonds25030 YearSecond Quarter See Note 5 to the consolidated financial statements for further information. **Current (2026):** Short-Term Funding Sources - Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments. Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are: •$2 billion for Xcel Energy Inc. •$1.2 billion for PSCo. •$800 million for NSP-Minnesota. •$600 million for SPS. •$150 million for NSP-Wisconsin. 42 42 42 Table of Contents Table of Contents See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - As of Feb. 23, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$2,000 $790 $1,210 $21 $1,231 PSCo1,200 308 892 9 901 NSP-Minnesota800 329 471 3 474 SPS600 213 387 11 398 NSP-Wisconsin150 - 150 2 152 Total$4,750 $1,640 $3,110 $46 $3,156 Term Loan (c)1,500 750 750 - 750 (a)Credit facilities expire in December 2029.(b)Includes outstanding commercial paper and letters of credit.(c)Xcel Energy Inc.'s $1.5 billion term loan (entered into in January 2026) matures in January 2027.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2025 and 2024, Xcel Energy had approximately 624 million shares and 574 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.Planned Financing Activity - Xcel Energy's 2026 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Xcel Energy Inc.Senior Unsecured Notes$1,000 PSCoFirst Mortgage Bonds2,400 NSP-MinnesotaFirst Mortgage Bonds1,000 SPSFirst Mortgage Bonds1,000 NSP-WisconsinFirst Mortgage Bonds250In addition, Xcel Energy plans to issue incremental equity throughout 2026 through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility.See Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2026 Earnings Guidance - Xcel Energy's 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. (a)Key assumptions as compared with 2025 actual levels unless noted:•Constructive outcomes in all pending rate case and regulatory proceedings.•Normal weather patterns for the year.•Weather-normalized retail electric sales are projected to increase ~3%.•Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $535 million to $545 million. •O&M expenses are projected to increase ~3%. •Depreciation expense is projected to increase approximately $350 million to $360 million.•Property taxes are projected to increase $30 million to $40 million. •Interest expense (net of AFUDC - debt) is projected to increase $300 million to $310 million, net of interest income. •AFUDC - equity is projected to increase $140 million to $150 million.(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management's view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:• Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share.• 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.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements - As of Feb. 23, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$2,000 $790 $1,210 $21 $1,231 PSCo1,200 308 892 9 901 NSP-Minnesota800 329 471 3 474 SPS600 213 387 11 398 NSP-Wisconsin150 - 150 2 152 Total$4,750 $1,640 $3,110 $46 $3,156 Term Loan (c)1,500 750 750 - 750 (a)Credit facilities expire in December 2029.(b)Includes outstanding commercial paper and letters of credit.(c)Xcel Energy Inc.'s $1.5 billion term loan (entered into in January 2026) matures in January 2027.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2025 and 2024, Xcel Energy had approximately 624 million shares and 574 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.Planned Financing Activity - Xcel Energy's 2026 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Xcel Energy Inc.Senior Unsecured Notes$1,000 PSCoFirst Mortgage Bonds2,400 NSP-MinnesotaFirst Mortgage Bonds1,000 SPSFirst Mortgage Bonds1,000 NSP-WisconsinFirst Mortgage Bonds250In addition, Xcel Energy plans to issue incremental equity throughout 2026 through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility.See Note 5 to the consolidated financial statements for further information. See Note 5 to the consolidated financial statements for further information. Credit Facility Agreements - As of Feb. 23, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$2,000 $790 $1,210 $21 $1,231 PSCo1,200 308 892 9 901 NSP-Minnesota800 329 471 3 474 SPS600 213 387 11 398 NSP-Wisconsin150 - 150 2 152 Total$4,750 $1,640 $3,110 $46 $3,156 Term Loan (c)1,500 750 750 - 750 Facility (a) Drawn (b) Term Loan (c) (a)Credit facilities expire in December 2029. (b)Includes outstanding commercial paper and letters of credit. (c)Xcel Energy Inc.'s $1.5 billion term loan (entered into in January 2026) matures in January 2027. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2025 and 2024, Xcel Energy had approximately 624 million shares and 574 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval. Planned Financing Activity - Xcel Energy's 2026 financing plans reflect the following: IssuerSecurityAmount (Millions of Dollars)Xcel Energy Inc.Senior Unsecured Notes$1,000 PSCoFirst Mortgage Bonds2,400 NSP-MinnesotaFirst Mortgage Bonds1,000 SPSFirst Mortgage Bonds1,000 NSP-WisconsinFirst Mortgage Bonds250 In addition, Xcel Energy plans to issue incremental equity throughout 2026 through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility. See Note 5 to the consolidated financial statements for further information. Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2026 Earnings Guidance - Xcel Energy's 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. (a)Key assumptions as compared with 2025 actual levels unless noted:•Constructive outcomes in all pending rate case and regulatory proceedings.•Normal weather patterns for the year.•Weather-normalized retail electric sales are projected to increase ~3%.•Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $535 million to $545 million. •O&M expenses are projected to increase ~3%. •Depreciation expense is projected to increase approximately $350 million to $360 million.•Property taxes are projected to increase $30 million to $40 million. •Interest expense (net of AFUDC - debt) is projected to increase $300 million to $310 million, net of interest income. •AFUDC - equity is projected to increase $140 million to $150 million.(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management's view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.Long-Term EPS and Dividend Growth Rate Objectives - Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:• Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share.• 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.ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the "Derivatives, Risk Management and Market Risk" section in Item 7, incorporated by reference.ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. --- ## Modified: Critical Audit Matter **Key changes:** - Reworded sentence: "The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments." **Prior (2025):** The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. **Current (2026):** The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 45 45 45 Table of Contents Table of Contents --- ## Modified: Additional Information on Regulatory Authority **Key changes:** - Reworded sentence: "Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations." - Reworded sentence: "PTCs earned for owned wind and solar generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC." - Reworded sentence: "Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Wildfire Mitigation AdjustmentRecovers actual 2025-2027 costs associated with wildfire mitigation.Pending and Recently Concluded Regulatory Proceedings2025 Colorado Electric Rate Case - In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins)." - Reworded sentence: "PTCs earned for owned wind and solar generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC." - Reworded sentence: "Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Wildfire Mitigation AdjustmentRecovers actual 2025-2027 costs associated with wildfire mitigation.Pending and Recently Concluded Regulatory Proceedings2025 Colorado Electric Rate Case - In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins)." **Prior (2025):** The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers. 31 31 31 Table of Contents Table of Contents Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.DSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer's bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Pending and Recently Concluded Regulatory ProceedingsColorado Natural Gas Rate Case - In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%). The request was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base. In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:•Use of a historic 2023 test year, with a 13-month average rate base.•Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.•Acceleration of $15 million per year of depreciation expense (incremental to PSCo's original rate request), to be held in an external trust for future decommissioning costs.•Modifications to recoverability of certain operating expenses.•Denial of PSCo's decoupling proposal.PSCo placed new rates into effect in November, as modified on ARRR in February 2025, with an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation. The UCA filed a second ARRR in February 2025, which remains pending. Colorado Resource Plan - In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs. In December 2023, the CPUC approved a framework for two PIMs associated with the generation projects in the portfolio - a PIM related to capital construction costs and another related to ongoing levelized energy costs with details to be further defined via subsequent proceedings throughout 2024. In September 2024, PSCo filed a proposal for implementation of the PIMs. Intervenor testimony is due Feb. 27, 2025, with a final decision expected in summer 2025. In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. In January 2025, the CPUC issued a decision granting limited potential pricing relief, subject to evaluation in future CPCN proceedings for company owned projects. PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and 2025.2024 Colorado Electric Resource Plan - In October 2024, PSCo filed its electric resource plan with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources. •The plan reflects a base sales forecast with 7% compound annual sales growth through 2031. •The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.•The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios. The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio. The table below summarizes two of the proposed portfolios based on the different sales scenarios: Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.DSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer's bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure. **Current (2026):** Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market. Pipeline safety compliance. 32 32 32 Table of Contents Table of Contents Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.Clean Energy Plan RevenueRecovers projects approved through the Clean Energy Plan to a maximum of 1.25% of the customer's bill.DSM Cost AdjustmentRecovers electric and gas DSM and CHP, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel, purchased energy costs and certain owned renewable generating assets. Short-term sales margins are shared with customers. PTCs earned for owned wind and solar generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. Gas Price Risk Management Plan reserves are also collected in this mechanism as gas prices permit.GMACRecovers select categories of distribution costs.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer's bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Wildfire Mitigation AdjustmentRecovers actual 2025-2027 costs associated with wildfire mitigation.Pending and Recently Concluded Regulatory Proceedings2025 Colorado Electric Rate Case - In November 2025, PSCo filed an electric rate case with the 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.PSCo's base rate request (millions of dollars):Distribution system investment$294 Liability insurance65 Operating costs51 Changes in cost of capital49 Coal retirements (a)(120)Other17 Rate request, net of rider roll-ins$356 (a)The case includes request for rider recovery of any costs associated with extending operations at Comanche Unit 2.A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.2025 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.PSCo's base rate request (millions of dollars):Capital investments$90 Changes in cost of capital53 Operating costs42 Sales/revenue growth(7)Other12 Total rate request$190 A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.2024 Colorado Natural Gas Rate Case - In January 2024, PSCo filed a natural gas rate case with the CPUC. In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation.In May 2025, PSCo filed an appeal with the Denver District Court seeking review of the CPUC's decisions related to recovery of certain operating expenses, cost of capital and capital structure, and the treatment of gas storage inventory costs. Briefing was completed in the fourth quarter of 2025. In the first quarter of 2026, the Denver District Court affirmed the CPUC's decision on all counts appealed by PSCo.Colorado Resource Plan - In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs. In September 2025, the CPUC authorized a process for company-owned and PPA resources to seek up to 15% relief for tariff impacts to projects. Relief requests are due by Dec. 31, 2025 or 18 months prior to COD. The CPUC will ultimately review and approve/deny requests. PSCo has filed all generation CPCNs associated with company-owned generation from the Colorado Resource Plan and expects to continue filing transmission CPCNs throughout 2026.2024 Colorado Electric Resource Plan - In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a load forecast that reflects a 3% compound annual sales growth through 2031 and generation capacity need of approximately 5,400 MW. PSCo filed a request for reconsideration of various aspects of the decision which were verbally approved in January 2026 (with a written decision related to those reconsideration requests expected in the first quarter of 2026). This decision is expected to initiate the Phase II competitive solicitation process with an RFP expected to be issued in the third quarter of 2026. This RFP will seek to acquire the balance of resource needs through 2031 (after consideration of any approved acquisitions from the Near-Term Procurement RFP).Near-Term Procurement - In August 2025, PSCo filed a joint motion with state agencies to initiate a "fast-tracked" solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 nameplate MW of clean energy resources, 200 accredited MW of firm, dispatchable resources, and up to 300 accredited MW of other dispatchable resources. Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer's bill.Clean Energy Plan RevenueRecovers projects approved through the Clean Energy Plan to a maximum of 1.25% of the customer's bill.DSM Cost AdjustmentRecovers electric and gas DSM and CHP, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel, purchased energy costs and certain owned renewable generating assets. Short-term sales margins are shared with customers. PTCs earned for owned wind and solar generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. Gas Price Risk Management Plan reserves are also collected in this mechanism as gas prices permit.GMACRecovers select categories of distribution costs.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer's bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Wildfire Mitigation AdjustmentRecovers actual 2025-2027 costs associated with wildfire mitigation.Pending and Recently Concluded Regulatory Proceedings2025 Colorado Electric Rate Case - In November 2025, PSCo filed an electric rate case with the 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.PSCo's base rate request (millions of dollars):Distribution system investment$294 Liability insurance65 Operating costs51 Changes in cost of capital49 Coal retirements (a)(120)Other17 Rate request, net of rider roll-ins$356 (a)The case includes request for rider recovery of any costs associated with extending operations at Comanche Unit 2.A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.2025 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. --- ## Modified: We are subject to commodity risks and other risks associated with energy markets and energy production. **Key changes:** - Reworded sentence: "A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations." - Reworded sentence: "Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity." - Reworded sentence: "We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas." - Reworded sentence: "Additionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, our risk management programs may not be effective to protect against significant adverse market fluctuations and our results of operations, financial condition or cash flows could be materially impacted." **Prior (2025):** In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Wildfires could jeopardize Xcel Energy's electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. 16 16 16 Table of Contents Table of Contents We have programs in place to mitigate the physical and financial risks associated with wildfires; however, Xcel Energy's wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when Xcel Energy follows its procedures and implements its wildfire mitigation initiatives.Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows.We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy's results of operations, financial condition or cash flows could be materially impacted. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. We have programs in place to mitigate the physical and financial risks associated with wildfires; however, Xcel Energy's wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when Xcel Energy follows its procedures and implements its wildfire mitigation initiatives.Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows.We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy's results of operations, financial condition or cash flows could be materially impacted. We have programs in place to mitigate the physical and financial risks associated with wildfires; however, Xcel Energy's wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when Xcel Energy follows its procedures and implements its wildfire mitigation initiatives. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows. **Current (2026):** A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity. A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Additionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, our risk management programs may not be effective to protect against significant adverse market fluctuations and our results of operations, financial condition or cash flows could be materially impacted. --- ## Modified: Credit Facility (a) **Key changes:** - Reworded sentence: "Drawn (b) (a)These credit facilities mature in December 2029." - Added sentence: "Term Loan Agreement - In January 2026, Xcel Energy Inc." - Added sentence: "entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility." - Added sentence: "The loan is unsecured and matures Jan." - Added sentence: "The term loan includes one financial covenant, requiring Xcel Energy's consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent." **Prior (2025):** Drawn (b) (a)These credit facilities mature in September 2027. These credit facilities mature in September 2027. (b)Includes outstanding commercial paper and letters of credit. Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023. **Current (2026):** Drawn (b) (a)These credit facilities mature in December 2029. These credit facilities mature in December 2029. (b)Includes outstanding commercial paper and letters of credit. Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2025 and 2024. Term Loan Agreement - In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility. The loan is unsecured and matures Jan. 30, 2027. The term loan includes one financial covenant, requiring Xcel Energy's consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent. Interest is at a rate equal to the Term SOFR rate, plus 85.0 basis points, or an alternate base rate. --- ## Modified: Nuclear Power Operations **Key changes:** - Reworded sentence: "Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation." - Reworded sentence: "After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas Adjustment (WI)A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services.Pending Regulatory ProceedingsExcess Liability Insurance Deferral - In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal." - Reworded sentence: "After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas Adjustment (WI)A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services." **Prior (2025):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. **Current (2026):** Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use. NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs. Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable. High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site. Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island. In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. 30 30 30 Table of Contents Table of Contents NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By April of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin's retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas Adjustment (WI)A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services.Pending Regulatory ProceedingsExcess Liability Insurance Deferral - In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. The PSCW issued a written approval in November 2025 and authorized recovery of the deferral over 2026 and 2027 in the Wisconsin Electric and Natural Gas Rate Case described below.Wisconsin Electric and Natural Gas Rate Case - In March 2025, NSP-Wisconsin filed a request with the PSCW for a multi-year electric and natural gas rate increase. Both the electric and natural gas rate requests were based on forward-looking 2026 and 2027 test years, with a 10.0% ROE and an equity ratio of 53.5%. In December 2025, the PSCW issued final written approval on NSP-Wisconsin's request, with a final rate increase of $126 million for the electric utility ($68 million in 2026, with an incremental $58 million in 2027) and $22 million for the natural gas utility ($18 million in 2026, with an incremental $4 million in 2027), based on a ROE of 9.8% and an equity ratio of 52.5%. (Millions of Dollars)ElectricNatural GasNSP-Wisconsin's filed two-year rate request$151 $24 PSCW decision:Capital investments(8)(1)ROE adjustment(7)(1)O&M expenses(5)(1)Nuclear decommissioning accrual update (a)(6) - Excess liability insurance deferral recovery4 1Other, net(3) - Total revenue change$126 $22 (a)Since filing the case, the MPUC authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral. Michigan Natural Gas Rate Case - In July 2025, NSP-Wisconsin filed a natural gas rate case in Michigan, seeking a revenue increase of $2.2 million. In December 2025, the MPSC issued a final written approval of the settlement order, with a final rate increase of $1.6 million ($0.7 million in 2026, with an incremental $0.9 million in 2027) based on a ROE of 9.8% and an equity ratio of 50%. NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By April of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin's natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin's retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas Adjustment (WI)A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services. --- ## Modified: Total revenue change **Key changes:** - Reworded sentence: "(a)Since filing the case, the MPUC authorized a reduction to the annual nuclear decommissioning accrual." - Reworded sentence: "NSP-Minnesota expects to file for approval of recommended projects in early 2026.•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit." - Removed sentence: "In February 2025, the MPUC verbally approved the terms of the settlement agreement, including: •The selection of the company owned 420 MW Lyon County combustion turbine." - Removed sentence: "•The selection of the company owned 300 MW 4-hour Sherco battery energy storage system." - Removed sentence: "•Multiple PPAs to proceed to the negotiation stage." **Prior (2025):** 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). **Current (2026):** (a)Since filing the case, the MPUC authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral. Michigan Natural Gas Rate Case - In July 2025, NSP-Wisconsin filed a natural gas rate case in Michigan, seeking a revenue increase of $2.2 million. In December 2025, the MPSC issued a final written approval of the settlement order, with a final rate increase of $1.6 million ($0.7 million in 2026, with an incremental $0.9 million in 2027) based on a ROE of 9.8% and an equity ratio of 50%. 31 31 31 Table of Contents Table of Contents NSP SystemPending and Recently Concluded Regulatory ProceedingsNSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects in early 2026.•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025. NSP-Minnesota filed for requisite approvals of the selected resources with the MPUC in the fourth quarter of 2025 (decision expected in early 2026); NSP-Wisconsin expects to file for approvals with the PSCW in 2026.•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar + storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota's Distributed Solar Energy Standard eligibility requirements. Bids are due in March 2026, and filing for MPUC approval is expected by the end of 2026, ahead of the established procedural schedule.•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of its Upper Midwest resource planning efforts. Large Load Agreement - In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement, in accordance with Minnesota's regulatory and legislative requirements for large loads. Requests for approval of the Electric Service Agreement and 1,900 MW of proposed renewable generation to support the data center is expected to be filed with the MPUC by April 2026. Purchased Power and Transmission ServicesThe NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance. NSP SystemPending and Recently Concluded Regulatory ProceedingsNSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects in early 2026.•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025. NSP-Minnesota filed for requisite approvals of the selected resources with the MPUC in the fourth quarter of 2025 (decision expected in early 2026); NSP-Wisconsin expects to file for approvals with the PSCW in 2026.•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar + storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota's Distributed Solar Energy Standard eligibility requirements. Bids are due in March 2026, and filing for MPUC approval is expected by the end of 2026, ahead of the established procedural schedule.•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of its Upper Midwest resource planning efforts. Large Load Agreement - In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement, in accordance with Minnesota's regulatory and legislative requirements for large loads. Requests for approval of the Electric Service Agreement and 1,900 MW of proposed renewable generation to support the data center is expected to be filed with the MPUC by April 2026. Purchased Power and Transmission ServicesThe NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers. NSP System --- ## Modified: Operating Cash Flows **Key changes:** - Reworded sentence: "31Cash provided by operating activities - 2024$4,641 Components of change - 2025 vs." - Reworded sentence: "31Cash used in investing activities - 2024$(7,428)Components of change - 2025 vs." **Prior (2025):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2023$5,327 Components of change - 2024 vs. 2023Higher net income165 Non-cash transactions222 Changes in deferred taxes284 Changes in working capital (783)Changes in net regulatory and other assets and liabilities(574)Cash provided by operating activities - 2024$4,641 Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2023$(5,926)Components of change - 2024 vs. 2023Increased capital expenditures(1,510)Other investing activities8 Cash used in investing activities - 2024$(7,428)Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2023$617 Components of change - 2024 vs. 2023Higher long-term debt issuances, net of repayments1,512 Higher proceeds from issuance of common stock847 Higher dividends paid to shareholders(83)Other financing activities(56)Cash provided by financing activities - 2024$2,837 Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023. The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information.Capital RequirementsXcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy's financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation. **Current (2026):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities - 2024$4,641 Components of change - 2025 vs. 2024Higher net income82 Non-cash transactions121 Changes in deferred taxes189 Changes in working capital (304)Changes in net regulatory and other assets and liabilities(646)Cash provided by operating activities - 2025$4,083 Net cash provided by operating activities decreased by $558 million for 2025 as compared to 2024. The decrease was largely due to the payment of the Marshall Wildfire settlement and timing of regulatory recovery, including deferred fuel costs. 40 40 40 Table of Contents Table of Contents Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2024$(7,428)Components of change - 2025 vs. 2024Increased capital expenditures(3,544)Other investing activities3 Cash used in investing activities - 2025$(10,969)Net cash used in investing activities increased by $3,541 million for 2025 as compared to 2024. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2024$2,837 Components of change - 2025 vs. 2024Higher long-term debt issuances, net of repayments1,059 Higher net short-term debt proceeds945 Higher proceeds from issuance of common stock2,232 Other financing activities(92)Cash provided by financing activities - 2025$6,981 Net cash provided by financing activities increased by $4,144 million for 2025 as compared to 2024. The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2024$(7,428)Components of change - 2025 vs. 2024Increased capital expenditures(3,544)Other investing activities3 Cash used in investing activities - 2025$(10,969)Net cash used in investing activities increased by $3,541 million for 2025 as compared to 2024. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects. --- ## Modified: Recently Issued **Key changes:** - Reworded sentence: "Government Grants - In December 2025, the FASB issued ASU 2025-10 - Government Grants (Topic 832), which includes amended recognition, measurement and presentation requirements for asset and income-related grants." - Reworded sentence: "31, 2024Property, plant and equipment, netElectric plant$61,892 $56,791 Natural gas plant10,517 9,834 Common and other property3,790 3,515 Plant to be retired (a)1,595 1,793 CWIP8,085 4,720 Total property, plant and equipment85,879 76,653 Less accumulated depreciation(20,710)(19,852)Nuclear fuel3,678 3,491 Less accumulated amortization(3,208)(3,094)Property, plant and equipment, net$65,639 $57,198 (a)Amounts include Sherco 1 and 3 and A.S." - Reworded sentence: "31, 2025:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$638 $515 59 %Sherco common facilities189 134 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 4 50 CapX2020887 169 51 Total NSP-Minnesota (a)$1,779 $830 (a)Projects additionally include $26 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $33 37 %CapX2020169 46 80 Total NSP-Wisconsin (a)$348 $79 (a)Projects additionally include $3 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$159 $126 76 %Hayden Unit 2152 99 37 Hayden common facilities45 36 53 Craig Units 1 and 282 60 10 Craig common facilities40 28 7 Comanche Unit 3971 233 67 Comanche common facilities29 6 77 Electric transmission:Transmission and other facilities193 76 VariousGas transmission:Rifle, CO to Avon, CO31 10 60 Gas transmission compressor8 3 60 Total PSCo (a)$1,710 $677 (a)Projects additionally include $16 million in CWIP.Each company separately records its share of operating expenses and construction expenditures." - Added sentence: "Disaggregation of Income Statement Expenses - In November 2024, the FASB issued ASU 2024-03 - Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses." - Added sentence: "The ASU is effective for annual reporting periods beginning after Dec." **Prior (2025):** Income Taxes - In December 2023, the FASB issued ASU 2023-09 - Income Taxes (Topic 740) - Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements. Climate-Related Disclosures - In March 2024, the SEC issued Final Rule 33-11275 - The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements. Disaggregation of Income Statement Expenses - In November 2024, the FASB issued ASU 2024-03 - Disaggregation of Income Statement Expenses, which requires disaggregated disclosure of income statement expenses for public business entities. The ASU is effective for annual periods beginning after Dec. 15, 2026. Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance. 56 56 56 Table of Contents Table of Contents 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Property, plant and equipment, netElectric plant$56,791 $52,494 Natural gas plant9,834 9,080 Common and other property3,515 3,190 Plant to be retired (a)1,793 2,055 CWIP4,720 2,873 Total property, plant and equipment76,653 69,692 Less accumulated depreciation(19,852)(18,399)Nuclear fuel3,491 3,337 Less accumulated amortization(3,094)(2,988)Property, plant and equipment, net$57,198 $51,642 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process. Amounts are presented net of accumulated depreciation.Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2024:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 (a)Projects additionally include $10 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $30 37 %CapX2020169 44 80 Total NSP-Wisconsin (a)$348 $74 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 (a)Projects additionally include $28 million in CWIP.Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Property, plant and equipment, netElectric plant$56,791 $52,494 Natural gas plant9,834 9,080 Common and other property3,515 3,190 Plant to be retired (a)1,793 2,055 CWIP4,720 2,873 Total property, plant and equipment76,653 69,692 Less accumulated depreciation(19,852)(18,399)Nuclear fuel3,491 3,337 Less accumulated amortization(3,094)(2,988)Property, plant and equipment, net$57,198 $51,642 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process. Amounts are presented net of accumulated depreciation.Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2024:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 (a)Projects additionally include $10 million in CWIP. **Current (2026):** Government Grants - In December 2025, the FASB issued ASU 2025-10 - Government Grants (Topic 832), which includes amended recognition, measurement and presentation requirements for asset and income-related grants. The ASU is effective for annual and interim reporting periods beginning after Dec. 15, 2028. Xcel Energy is currently evaluating the new guidance, but adoption impacts are expected to be immaterial. 55 55 55 Table of Contents Table of Contents Disaggregation of Income Statement Expenses - In November 2024, the FASB issued ASU 2024-03 - Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual reporting periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is currently evaluating the impact of the new disclosure guidance.3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024Property, plant and equipment, netElectric plant$61,892 $56,791 Natural gas plant10,517 9,834 Common and other property3,790 3,515 Plant to be retired (a)1,595 1,793 CWIP8,085 4,720 Total property, plant and equipment85,879 76,653 Less accumulated depreciation(20,710)(19,852)Nuclear fuel3,678 3,491 Less accumulated amortization(3,208)(3,094)Property, plant and equipment, net$65,639 $57,198 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation.Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2025:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$638 $515 59 %Sherco common facilities189 134 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 4 50 CapX2020887 169 51 Total NSP-Minnesota (a)$1,779 $830 (a)Projects additionally include $26 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $33 37 %CapX2020169 46 80 Total NSP-Wisconsin (a)$348 $79 (a)Projects additionally include $3 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$159 $126 76 %Hayden Unit 2152 99 37 Hayden common facilities45 36 53 Craig Units 1 and 282 60 10 Craig common facilities40 28 7 Comanche Unit 3971 233 67 Comanche common facilities29 6 77 Electric transmission:Transmission and other facilities193 76 VariousGas transmission:Rifle, CO to Avon, CO31 10 60 Gas transmission compressor8 3 60 Total PSCo (a)$1,710 $677 (a)Projects additionally include $16 million in CWIP.Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. Disaggregation of Income Statement Expenses - In November 2024, the FASB issued ASU 2024-03 - Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual reporting periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is currently evaluating the impact of the new disclosure guidance.3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024Property, plant and equipment, netElectric plant$61,892 $56,791 Natural gas plant10,517 9,834 Common and other property3,790 3,515 Plant to be retired (a)1,595 1,793 CWIP8,085 4,720 Total property, plant and equipment85,879 76,653 Less accumulated depreciation(20,710)(19,852)Nuclear fuel3,678 3,491 Less accumulated amortization(3,208)(3,094)Property, plant and equipment, net$65,639 $57,198 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation.Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries' jointly owned assets as of Dec. 31, 2025:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$638 $515 59 %Sherco common facilities189 134 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 4 50 CapX2020887 169 51 Total NSP-Minnesota (a)$1,779 $830 (a)Projects additionally include $26 million in CWIP. Disaggregation of Income Statement Expenses - In November 2024, the FASB issued ASU 2024-03 - Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual reporting periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is currently evaluating the impact of the new disclosure guidance. --- ## Modified: Major classes of property, plant and equipment **Key changes:** - Reworded sentence: "31, 2024Property, plant and equipment, netElectric plant$61,892 $56,791 Natural gas plant10,517 9,834 Common and other property3,790 3,515 Plant to be retired (a)1,595 1,793 CWIP8,085 4,720 Total property, plant and equipment85,879 76,653 Less accumulated depreciation(20,710)(19,852)Nuclear fuel3,678 3,491 Less accumulated amortization(3,208)(3,094)Property, plant and equipment, net$65,639 $57,198 Plant to be retired (a) (a)Amounts include Sherco 1 and 3 and A.S." - Added sentence: "Amounts include Sherco 1 and 3 and A.S." - Added sentence: "King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS." - Added sentence: "31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete)." - Added sentence: "Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025." **Prior (2025):** (Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Property, plant and equipment, netElectric plant$56,791 $52,494 Natural gas plant9,834 9,080 Common and other property3,515 3,190 Plant to be retired (a)1,793 2,055 CWIP4,720 2,873 Total property, plant and equipment76,653 69,692 Less accumulated depreciation(19,852)(18,399)Nuclear fuel3,491 3,337 Less accumulated amortization(3,094)(2,988)Property, plant and equipment, net$57,198 $51,642 Plant to be retired (a) (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process. Amounts are presented net of accumulated depreciation. **Current (2026):** (Millions of Dollars)Dec. 31, 2025Dec. 31, 2024Property, plant and equipment, netElectric plant$61,892 $56,791 Natural gas plant10,517 9,834 Common and other property3,790 3,515 Plant to be retired (a)1,595 1,793 CWIP8,085 4,720 Total property, plant and equipment85,879 76,653 Less accumulated depreciation(20,710)(19,852)Nuclear fuel3,678 3,491 Less accumulated amortization(3,208)(3,094)Property, plant and equipment, net$65,639 $57,198 Plant to be retired (a) (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation. Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation. --- ## Modified: Investing Cash Flows **Key changes:** - Reworded sentence: "31Cash used in investing activities - 2024$(7,428)Components of change - 2025 vs." - Added sentence: "Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec." - Added sentence: "31Cash provided by financing activities - 2024$2,837 Components of change - 2025 vs." - Added sentence: "2024Higher long-term debt issuances, net of repayments1,059 Higher net short-term debt proceeds945 Higher proceeds from issuance of common stock2,232 Other financing activities(92)Cash provided by financing activities - 2025$6,981 Net cash provided by financing activities increased by $4,144 million for 2025 as compared to 2024." - Added sentence: "The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information." **Prior (2025):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2023$(5,926)Components of change - 2024 vs. 2023Increased capital expenditures(1,510)Other investing activities8 Cash used in investing activities - 2024$(7,428) Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects. **Current (2026):** (Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities - 2024$(7,428)Components of change - 2025 vs. 2024Increased capital expenditures(3,544)Other investing activities3 Cash used in investing activities - 2025$(10,969) Net cash used in investing activities increased by $3,541 million for 2025 as compared to 2024. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects. Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities - 2024$2,837 Components of change - 2025 vs. 2024Higher long-term debt issuances, net of repayments1,059 Higher net short-term debt proceeds945 Higher proceeds from issuance of common stock2,232 Other financing activities(92)Cash provided by financing activities - 2025$6,981 Net cash provided by financing activities increased by $4,144 million for 2025 as compared to 2024. The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information. --- ## Modified: CONSOLIDATED STATEMENTS OF CASH FLOWS **Key changes:** - Reworded sentence: "31 202520242023Operating activities Net income$2,018 $1,936 $1,771 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,968 2,769 2,471 Nuclear fuel amortization114 106 96 Deferred income taxes414 225 (59)Allowance for equity funds used during construction(281)(168)(91)Earnings from equity method investments(17)(19)(35)Dividends from equity method investments32 34 35 Provision for bad debts61 47 79 Share-based compensation expense46 33 25 Changes in operating assets and liabilities:Accounts receivable(129)19 (27)Accrued unbilled revenues(48)21 252 Inventories(300)(140)(98)Other current assets(122)(139)86 Accounts payable(50)37 (149)Net regulatory assets and liabilities(189)436 911 Other current liabilities(174)(317)200 Pension and other employee benefit obligations(100)(89)17 Other, net(160)(150)(157)Net cash provided by operating activities4,083 4,641 5,327 Investing activitiesCapital/construction expenditures(10,908)(7,364)(5,854)Purchase of investment securities(1,200)(998)(994)Proceeds from the sale of investment securities1,197 961 959 Other, net(58)(27)(37)Net cash used in investing activities(10,969)(7,428)(5,926)Financing activitiesProceeds (repayments) of short-term borrowings, net855 (90)(28)Proceeds from issuances of long-term debt5,763 3,647 2,630 Repayments of long-term debt(1,713)(656)(1,151)Proceeds from issuance of common stock3,349 1,117 270 Dividends paid(1,282)(1,175)(1,092)Other, net9 (6)(12)Net cash provided by financing activities6,981 2,837 617 Net change in cash and cash equivalents95 50 18 Cash, cash equivalents and restricted cash at beginning of period179 129 111 Cash, cash equivalents and restricted cash at end of period$274 $179 $129 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(1,262)$(1,131)$(945)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$1,170 $964 $553 Inventory transfers to property, plant and equipment348 258 197 Operating and finance lease right-of-use assets1,253 138 238 Allowance for equity funds used during construction281 168 91 Issuance of common stock for reinvested dividends and/or equity awards80 68 64 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents" **Prior (2025):** (amounts in millions) Year Ended Dec. 31 202420232022Operating activities Net income$1,936 $1,771 $1,736 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,769 2,471 2,436 Nuclear fuel amortization106 96 118 Deferred income taxes225 (59)(140)Allowance for equity funds used during construction(168)(91)(75)Earnings from equity method investments(19)(35)(36)Dividends from equity method investments34 35 37 Provision for bad debts47 79 73 Share-based compensation expense33 25 20 Changes in operating assets and liabilities:Accounts receivable19 (27)(429)Accrued unbilled revenues21 252 (243)Inventories(140)(98)(203)Other current assets(139)86 (58)Accounts payable37 (149)195 Net regulatory assets and liabilities436 911 570 Other current liabilities(317)200 102 Pension and other employee benefit obligations(89)17 (49)Other, net(150)(157)(122)Net cash provided by operating activities4,641 5,327 3,932 Investing activitiesCapital/construction expenditures(7,364)(5,854)(4,638)Purchase of investment securities(998)(994)(1,332)Proceeds from the sale of investment securities961 959 1,297 Other, net(27)(37)20 Net cash used in investing activities(7,428)(5,926)(4,653)Financing activitiesRepayments of short-term borrowings, net(90)(28)(192)Proceeds from issuances of long-term debt3,647 2,630 2,164 Repayments of long-term debt(656)(1,151)(601)Proceeds from issuance of common stock1,117 270 322 Dividends paid(1,175)(1,092)(1,012)Other, net(6)(12)(15)Net cash provided by financing activities2,837 617 666 Net change in cash and cash equivalents50 18 (55)Cash, cash equivalents and restricted cash at beginning of period129 111 166 Cash, cash equivalents and restricted cash at end of period$179 $129 $111 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(1,131)$(945)$(887)Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers588 92 (15)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$964 $553 $626 Inventory transfers to property, plant and equipment258 197 78 Operating lease right-of-use assets138 238 141 Allowance for equity funds used during construction168 91 75 Issuance of common stock for reinvested dividends and/or equity awards68 64 57 See Notes to Consolidated Financial Statements 50 50 50 Table of Contents Table of Contents **Current (2026):** (amounts in millions) Year Ended Dec. 31 202520242023Operating activities Net income$2,018 $1,936 $1,771 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,968 2,769 2,471 Nuclear fuel amortization114 106 96 Deferred income taxes414 225 (59)Allowance for equity funds used during construction(281)(168)(91)Earnings from equity method investments(17)(19)(35)Dividends from equity method investments32 34 35 Provision for bad debts61 47 79 Share-based compensation expense46 33 25 Changes in operating assets and liabilities:Accounts receivable(129)19 (27)Accrued unbilled revenues(48)21 252 Inventories(300)(140)(98)Other current assets(122)(139)86 Accounts payable(50)37 (149)Net regulatory assets and liabilities(189)436 911 Other current liabilities(174)(317)200 Pension and other employee benefit obligations(100)(89)17 Other, net(160)(150)(157)Net cash provided by operating activities4,083 4,641 5,327 Investing activitiesCapital/construction expenditures(10,908)(7,364)(5,854)Purchase of investment securities(1,200)(998)(994)Proceeds from the sale of investment securities1,197 961 959 Other, net(58)(27)(37)Net cash used in investing activities(10,969)(7,428)(5,926)Financing activitiesProceeds (repayments) of short-term borrowings, net855 (90)(28)Proceeds from issuances of long-term debt5,763 3,647 2,630 Repayments of long-term debt(1,713)(656)(1,151)Proceeds from issuance of common stock3,349 1,117 270 Dividends paid(1,282)(1,175)(1,092)Other, net9 (6)(12)Net cash provided by financing activities6,981 2,837 617 Net change in cash and cash equivalents95 50 18 Cash, cash equivalents and restricted cash at beginning of period179 129 111 Cash, cash equivalents and restricted cash at end of period$274 $179 $129 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(1,262)$(1,131)$(945)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$1,170 $964 $553 Inventory transfers to property, plant and equipment348 258 197 Operating and finance lease right-of-use assets1,253 138 238 Allowance for equity funds used during construction281 168 91 Issuance of common stock for reinvested dividends and/or equity awards80 68 64 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents --- ## Modified: Wholesale and Commodity Marketing Operations **Key changes:** - Reworded sentence: "SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products." - Reworded sentence: "Tariffs, Trade Complaints and Federal ActionsSeveral trade cases related to anti-dumping and countervailing duty investigations are ongoing and we continue to monitor the potential impacts of these cases." - Reworded sentence: "The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States.In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS." - Reworded sentence: "In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million." - Reworded sentence: "OtherSupply Chain Xcel Energy's ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain." **Prior (2025):** Xcel Energy's ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability. In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work. Tariffs and Trade ComplaintsIn May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules. In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. In November 2024, the U.S. Department of Commerce concluded that dumping had occurred and the impact to Xcel Energy is still being evaluated. In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.In January of 2025, the U.S. International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China. This case will be reviewed by the U.S. Department of Commerce and the International Trade Commission over the course of 2025.In early 2025, several executive orders were issued, some of which impose new tariffs on certain imports, which may impact our procurement activities. Xcel Energy continues to assess the impacts of these tariffs, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs. In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work. Tariffs and Trade Complaints In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules. In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. In November 2024, the U.S. Department of Commerce concluded that dumping had occurred and the impact to Xcel Energy is still being evaluated. In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications. In January of 2025, the U.S. International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China. This case will be reviewed by the U.S. Department of Commerce and the International Trade Commission over the course of 2025. In early 2025, several executive orders were issued, some of which impose new tariffs on certain imports, which may impact our procurement activities. Xcel Energy continues to assess the impacts of these tariffs, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions. Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs. 35 35 35 Table of Contents Table of Contents Excess Liability Insurance CoverageXcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy's employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states. Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2024 and 2023, Xcel Energy had regulatory assets of $3.4 billion and $3.4 billion, respectively and regulatory liabilities of $6.9 billion and $6.4 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2024, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information.Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. Excess Liability Insurance CoverageXcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy's employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states. Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy's results of operations, financial condition or cash flows, and require management's most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income. **Current (2026):** NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCo --- ## Modified: Additional Information **Key changes:** - Reworded sentence: "A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services." **Prior (2025):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. **Current (2026):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. --- ## Modified: Federal tax law may significantly impact our business. **Key changes:** - Added sentence: "Macroeconomic RisksEconomic conditions impact our business.Xcel Energy's operations are affected by economic conditions, which correlates to customers/sales growth (decline)." - Added sentence: "Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers' ability to pay their bills, which could lead to additional bad debt expense." - Added sentence: "Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows." - Added sentence: "Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies." - Added sentence: "We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use." **Prior (2025):** Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources. **Current (2026):** Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources. Macroeconomic RisksEconomic conditions impact our business.Xcel Energy's operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers' ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. --- ## Modified: Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2025Common Stock Outstanding (Shares) as of Dec. 31, 20241,000,000,000 $2.50 623,600,715 574,365,598 **Key changes:** - Reworded sentence: "31, 2025: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2025NSP-Minnesota47.25 %57.75 %53.16 %NSP-Wisconsin (a)52.50 N/A52.66 SPS (b)45.00 55.00 54.47 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level." - Reworded sentence: "(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$2,185 $19,547 $22,607 NSP-Wisconsin12 3,318 N/ASPS (a)622 8,888 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating." **Prior (2025):** Dividend and Other Capital-Related Restrictions - Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.'s utility subsidiaries' dividends are subject to the FERC's jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2024: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2024NSP-Minnesota47.6 %58.2 %53.0 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.4 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. (b) Excludes short-term debt. Excludes short-term debt. (Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,809 $17,490 $17,800 NSP-Wisconsin12 2,922 N/ASPS (a)592 7,789 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating. (a) Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2024: (Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota (a)52.4% of total capitalization$2,670 NSP-Wisconsin$225 150 PSCo1,300 1,200 SPS150 700 NSP-Minnesota (a) (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. 6. RevenuesRevenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy's operating revenues consisted of the following: Year Ended Dec. 31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 - 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 - - 645 Transmission648 - - 648 Other64 175 - 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 - 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 - - 815 Transmission649 - - 649 Other63 156 - 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 - 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 - - 1,354 Transmission675 - - 675 Other97 178 - 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 **Current (2026):** Dividend and Other Capital-Related Restrictions - Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.'s utility subsidiaries' dividends are subject to the FERC's jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2025: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2025NSP-Minnesota47.25 %57.75 %53.16 %NSP-Wisconsin (a)52.50 N/A52.66 SPS (b)45.00 55.00 54.47 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. (b) Excludes short-term debt. Excludes short-term debt. (Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$2,185 $19,547 $22,607 NSP-Wisconsin12 3,318 N/ASPS (a)622 8,888 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating. (a) --- ## Modified: Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs. **Key changes:** - Added sentence: "Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs." - Added sentence: "The PHMSA is responsible for administering the DOT's national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines." - Added sentence: "The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure." - Added sentence: "We have programs in place to comply with these regulations, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations." - Added sentence: "Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services." **Prior (2025):** Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential reputational impact. Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to: •Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. •Failures in the availability, acquisition or transportation of fuel or other supplies. •Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns •Performance below expected or contracted levels of output or efficiency. •Availability of replacement or new equipment. •Availability of adequate water resources and ability to satisfy water intake and discharge requirements. •Inability to identify, manage properly or mitigate equipment defects. •Use of new or unproven technology. •Inability to use information effectively given the rapidly increasing volume of data. •Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources. •Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes. •Increased costs due to aging infrastructure. 15 15 15 Table of Contents Table of Contents Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT's national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services. Our utility operations are subject to long-term planning and project risks.Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy's long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. Our utilities have physical and financial risks associated with wildfires.In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Wildfires could jeopardize Xcel Energy's electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT's national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services. Our utility operations are subject to long-term planning and project risks.Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy's long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT's national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations. Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services. **Current (2026):** Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential reputational impact. Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT's national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations. Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services. Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to:•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. •Failures in the availability, acquisition or transportation of fuel or other supplies. •Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns.•Performance below expected or contracted levels of output or efficiency.•Availability of replacement or new equipment. •Availability of adequate water resources and ability to satisfy water intake and discharge requirements. •Inability to identify, manage properly or mitigate equipment defects. •Use of new or unproven technology. •Inability to use information effectively given the rapidly increasing volume of data.•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.•Risks associated with increased reliance on natural gas generation, including gas price volatility and supply constraints during extreme weather events.•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.•Risks of thermal runaway incidents associated with large battery storage facilities •Risks associated with aging infrastructure.•Risks associated with failures of other business processes and systems.•Risks associated with regulatory requirements that may extend the operation of our coal facilities beyond planned retirement dates and require additional investments.•Inability to deliver energy across transmission facilities, including due to congestion, outages, extreme weather, physical or cyber events, delays in construction or upgrades, permitting or siting challenges, or interconnection constraints.Our utility operations, resource adequacy and system reliability are subject to long-term planning and project risks.Our ability to reliably serve customer demand depends on the availability of sufficient generation and capacity resources. Changes in load growth, resource retirements, accreditation of resources, generation performance, extreme weather events, or delays in development or delivery of new resources, including the necessary transmission infrastructure, could affect resource adequacy and system reliability. Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to: •Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. •Failures in the availability, acquisition or transportation of fuel or other supplies. •Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns. •Performance below expected or contracted levels of output or efficiency. •Availability of replacement or new equipment. •Availability of adequate water resources and ability to satisfy water intake and discharge requirements. •Inability to identify, manage properly or mitigate equipment defects. •Use of new or unproven technology. •Inability to use information effectively given the rapidly increasing volume of data. •Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources. •Risks associated with increased reliance on natural gas generation, including gas price volatility and supply constraints during extreme weather events. •Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes. •Risks of thermal runaway incidents associated with large battery storage facilities •Risks associated with aging infrastructure. •Risks associated with failures of other business processes and systems. •Risks associated with regulatory requirements that may extend the operation of our coal facilities beyond planned retirement dates and require additional investments. •Inability to deliver energy across transmission facilities, including due to congestion, outages, extreme weather, physical or cyber events, delays in construction or upgrades, permitting or siting challenges, or interconnection constraints. --- ## Modified: Pending and Recently Concluded Regulatory Proceedings **Key changes:** - Reworded sentence: "2025 Colorado Electric Rate Case - In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins)." - Reworded sentence: "In September 2025, the CPUC authorized a process for company-owned and PPA resources to seek up to 15% relief for tariff impacts to projects." - Reworded sentence: "Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.SPSSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPUCTRetail electric operations, rates, services, construction of transmission or generation and other aspects of SPS' electric operations.The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities." - Reworded sentence: "PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.Purchased Transmission Services - In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers." - Reworded sentence: "PSCo made a filing in June 2025 to implement the mechanism and filed an unopposed settlement agreement in November 2025." **Prior (2025):** 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). **Current (2026):** 2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. 29 29 29 Table of Contents Table of Contents In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026. 2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026. The procedural schedule is as follows: •Intervenor direct testimony: March 20, 2026 •Rebuttal testimony: April 14, 2026 •Evidentiary Hearing: April 28-30, 2026 A SDPUC decision is expected in the first half of 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. --- ## Modified: CONSOLIDATED STATEMENTS OF INCOME **Key changes:** - Reworded sentence: "31202520242023Operating revenuesElectric$12,160 $11,147 $11,446 Natural gas2,452 2,230 2,645 Other57 64 115 Total operating revenues14,669 13,441 14,206 Operating expensesElectric fuel and purchased power3,961 3,788 4,278 Cost of natural gas sold and transported1,041 951 1,456 Cost of sales - other11 14 49 Operating and maintenance expenses2,732 2,540 2,444 Conservation and demand side management expenses406 394 286 Depreciation and amortization2,953 2,744 2,448 Taxes (other than income taxes)686 624 657 Marshall Wildfire litigation296 - - Loss on Comanche Unit 3 litigation - - 35 Workforce reduction expenses - - 72 Total operating expenses12,086 11,055 11,725 Operating income2,583 2,386 2,481 Other income, net235 143 22 Earnings from equity method investments17 19 35 Allowance for funds used during construction - equity281 168 91 Interest charges and financing costsInterest charges - includes other financing costs1,468 1,255 1,055 Allowance for funds used during construction - debt(125)(73)(51)Total interest charges and financing costs1,343 1,182 1,004 Income before income taxes1,773 1,534 1,625 Income tax benefit(245)(402)(146)Net income$2,018 $1,936 $1,771 Weighted average common shares outstanding:Basic587 563 552 Diluted589 563 552 Earnings per average common share:Basic$3.44 $3.44 $3.21 Diluted3.42 3.44 3.21 See Notes to Consolidated Financial Statements 47 47 47 Table of Contents Table of Contents" **Prior (2025):** (amounts in millions, except per share data) Year Ended Dec. 31202420232022Operating revenuesElectric$11,147 $11,446 $12,123 Natural gas2,230 2,645 3,080 Other64 115 107 Total operating revenues13,441 14,206 15,310 Operating expensesElectric fuel and purchased power3,788 4,278 5,005 Cost of natural gas sold and transported951 1,456 1,910 Cost of sales - other14 49 44 Operating and maintenance expenses2,540 2,444 2,491 Conservation and demand side management expenses394 286 331 Depreciation and amortization2,744 2,448 2,413 Taxes (other than income taxes)624 657 688 Loss on Comanche Unit 3 litigation - 35 - Workforce reduction expenses - 72 - Total operating expenses11,055 11,725 12,882 Operating income2,386 2,481 2,428 Other income (expense), net143 22 (13)Earnings from equity method investments19 35 36 Allowance for funds used during construction - equity168 91 75 Interest charges and financing costsInterest charges - includes other financing costs1,255 1,055 953 Allowance for funds used during construction - debt(73)(51)(28)Total interest charges and financing costs1,182 1,004 925 Income before income taxes1,534 1,625 1,601 Income tax benefit(402)(146)(135)Net income$1,936 $1,771 $1,736 Weighted average common shares outstanding:Basic563 552 547 Diluted563 552 547 Earnings per average common share:Basic$3.44 $3.21 $3.18 Diluted3.44 3.21 3.17 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents **Current (2026):** (amounts in millions, except per share data) Year Ended Dec. 31202520242023Operating revenuesElectric$12,160 $11,147 $11,446 Natural gas2,452 2,230 2,645 Other57 64 115 Total operating revenues14,669 13,441 14,206 Operating expensesElectric fuel and purchased power3,961 3,788 4,278 Cost of natural gas sold and transported1,041 951 1,456 Cost of sales - other11 14 49 Operating and maintenance expenses2,732 2,540 2,444 Conservation and demand side management expenses406 394 286 Depreciation and amortization2,953 2,744 2,448 Taxes (other than income taxes)686 624 657 Marshall Wildfire litigation296 - - Loss on Comanche Unit 3 litigation - - 35 Workforce reduction expenses - - 72 Total operating expenses12,086 11,055 11,725 Operating income2,583 2,386 2,481 Other income, net235 143 22 Earnings from equity method investments17 19 35 Allowance for funds used during construction - equity281 168 91 Interest charges and financing costsInterest charges - includes other financing costs1,468 1,255 1,055 Allowance for funds used during construction - debt(125)(73)(51)Total interest charges and financing costs1,343 1,182 1,004 Income before income taxes1,773 1,534 1,625 Income tax benefit(245)(402)(146)Net income$2,018 $1,936 $1,771 Weighted average common shares outstanding:Basic587 563 552 Diluted589 563 552 Earnings per average common share:Basic$3.44 $3.44 $3.21 Diluted3.42 3.44 3.21 See Notes to Consolidated Financial Statements 47 47 47 Table of Contents Table of Contents --- ## Modified: Income Tax Accruals **Key changes:** - Added sentence: "Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees." - Added sentence: "Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.)." - Added sentence: "In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time." - Added sentence: "Pension assumptions are continually reviewed.At Dec." - Added sentence: "31, 2025, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which remains unchanged from the rate set at Dec." **Prior (2025):** Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR. Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed. In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits. Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information. **Current (2026):** Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR. Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed. In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits. Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information. Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.At Dec. 31, 2025, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which remains unchanged from the rate set at Dec. 31, 2024. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2025, which remains unchanged from the rate set in 2024. Xcel Energy's pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan's funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.78% and 5.66% at Dec. 31, 2025, respectively. This represents a 10 basis point and 22 basis point decrease, respectively, from 2024. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2026 pension costs, net of the effects of regulation:Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$22 Discount rate (4) - Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy's actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.As of Dec. 31, 2025, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy's retiree medical plan. --- ## Modified: Purchased Power and Transmission Services **Key changes:** - Reworded sentence: "The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements." **Prior (2025):** Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market. Pipeline safety compliance. **Current (2026):** The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power - Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services - NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers. Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo's balancing authority area and at market-based prices to customers outside PSCo's balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO's, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance. --- ## Modified: Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. **Key changes:** - Added sentence: "We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk." - Added sentence: "Physical risks include changes in weather conditions and extreme weather events." - Added sentence: "Our customers' energy needs vary with weather." - Added sentence: "To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease." - Added sentence: "Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure." **Prior (2025):** Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows. **Current (2026):** Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows. We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers' energy needs vary with weather. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. Our utilities have significant risks associated with wildfires.In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in availability of vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other environmental factors have increased both the frequency and duration of fire weather conditions and the potential impact of an event. The expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Also, wildfires could jeopardize Xcel Energy's electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Our current wildfire mitigation initiatives may not be effective in preventing or reducing ignitions and wildfire-related losses.Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, damage amounts could exceed our coverage (as experienced with the Marshall Wildfire settlement in 2025) and negatively impact our results of operations, financial condition or cash flows. --- ## Modified: Additional Information **Key changes:** - Reworded sentence: "Recovers distribution costs not included in rates in Texas, including recovery of deferred Texas System Resiliency Plan costs." - Reworded sentence: "34 34 34 Table of Contents Table of Contents Pending and Recently Concluded Regulatory Proceedings2025 New Mexico Electric Rate Case - In November 2025, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $175 million (16.7%)." **Prior (2025):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. **Current (2026):** Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderReturns benefits and recovers costs from investments benefiting customers in South Dakota.Natural Gas Innovation Act RiderRecovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. --- ## Modified: Pending and Recently Concluded Regulatory Proceedings **Key changes:** - Reworded sentence: "2025 New Mexico Electric Rate Case - In November 2025, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $175 million (16.7%)." - Reworded sentence: "The proposed SRP covers 2025-2028 and includes a proposed $538 million of investment.In April 2025, SPS filed a unanimous stipulation and settlement agreement." - Reworded sentence: "Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement." **Prior (2025):** 2024 Minnesota Natural Gas Rate Case - In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case - In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). **Current (2026):** 2025 Minnesota Natural Gas Rate Case - In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026. 2022 Minnesota Electric Rate Case - In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. 29 29 29 Table of Contents Table of Contents In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026.Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.The procedural schedule is as follows:•Intervenor direct testimony: March 20, 2026•Rebuttal testimony: April 14, 2026•Evidentiary Hearing: April 28-30, 2026A SDPUC decision is expected in the first half of 2026.2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026. 2024 Minnesota Electric Rate Case - In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations. In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota's proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%. An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026. 2025 South Dakota Electric Rate Case - In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026. The procedural schedule is as follows: •Intervenor direct testimony: March 20, 2026 •Rebuttal testimony: April 14, 2026 •Evidentiary Hearing: April 28-30, 2026 A SDPUC decision is expected in the first half of 2026. 2024 North Dakota Electric Rate Case - In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%. 2026 North Dakota Natural Gas Rate Case - In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026. Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation - The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal - Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal - The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage - NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations. --- ## Modified: Loss Contingencies - Wildfires **Key changes:** - Reworded sentence: "Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigation, legal proceedings, mediations and settlements are considered." - Added sentence: "Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business." - Added sentence: "Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity." - Added sentence: "All financial and commodity-related instruments, including derivatives, are subject to market risk." - Added sentence: "Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives." **Prior (2025):** The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 12 accompanying the consolidated financial statements for additional information. **Current (2026):** The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigation, legal proceedings, mediations and settlements are considered. See Note 12 accompanying the consolidated financial statements for additional information. Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2025:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(10)$(15)$(3)$(1)$(29)NSP-Minnesota (b)1 (2) - (4)(5)PSCo (a)(1) - - - (1)$(10)$(17)$(3)$(5)$(35)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$ - $10 $10 $ - $20 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods. --- ## Modified: Changes in Diluted EPS **Key changes:** - Reworded sentence: "Components significantly contributing to changes in 2025 EPS compared with 2024: Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec." **Prior (2025):** Components significantly contributing to changes in 2024 EPS compared with 2023: Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS - 2023$3.21 Components of change - 2024 vs. 2023Electric regulatory rate outcomes and riders0.73 Higher other income, net0.16 Natural gas regulatory rate outcomes and riders0.14 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Higher depreciation and amortization(0.40)Interest charges, net of AFUDC - debt(0.24)Higher O&M expenses(0.13)Sherco Unit 3 2011 outage refunds(0.06)Other, net(0.11)GAAP diluted EPS - 2024$3.44 Sherco Unit 3 2011 outage refunds0.06 Ongoing diluted EPS - 2024$3.50 ROE for Xcel Energy and its utility subsidiaries: 20242023ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.07 %9.46 %8.82 %9.11 %PSCo7.63 7.63 7.32 7.77 SPS9.57 9.57 9.80 9.98 NSP-Wisconsin8.98 8.98 10.38 10.67 Utility Subsidiaries8.55 8.69 8.45 8.79 Xcel Energy10.42 10.61 10.33 10.79 **Current (2026):** Components significantly contributing to changes in 2025 EPS compared with 2024: Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS - 2024$3.44 Components of change - 2025 vs. 2024Higher electric revenues1.27 Higher natural gas revenues0.29 Higher AFUDC equity & debt0.27 Marshall Wildfire settlement(0.38)Higher interest charges(0.28)Higher depreciation and amortization(0.28)Higher O&M expenses(0.25)Higher electric fuel and purchased power (a)(0.23)Common equity financing(0.18)Higher costs of natural gas sold and transported (a)(0.12)Other, net(0.13)GAAP diluted EPS - 2025$3.42 Marshall Wildfire settlement0.38 Ongoing diluted EPS - 2025$3.80 Higher electric fuel and purchased power (a) Higher costs of natural gas sold and transported (a) (a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue. ROE for Xcel Energy and its utility subsidiaries: 20252024ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.19 %9.19 %9.07 %9.46 %PSCo5.66 7.55 7.63 7.63 SPS8.70 8.70 9.57 9.57 NSP-Wisconsin9.09 9.09 8.98 8.98 Utility Subsidiaries7.60 8.40 8.55 8.69 Xcel Energy9.36 10.38 10.42 10.61 --- ## Modified: CONSOLIDATED BALANCE SHEETS **Key changes:** - Reworded sentence: "3120252024AssetsCurrent assetsCash and cash equivalents$274 $179 Accounts receivable, net1,330 1,249 Accrued unbilled revenues880 832 Inventories761 666 Regulatory assets529 561 Derivative instruments165 114 Prepayments and other1,075 724 Total current assets5,014 4,325 Property, plant and equipment, net65,639 57,198 Other assetsNuclear decommissioning fund and other investments4,389 3,896 Regulatory assets2,998 2,849 Derivative instruments54 72 Operating lease right-of-use assets893 1,060 Finance lease right-of-use assets1,348 111 Other1,036 524 Total other assets10,718 8,512 Total assets$81,371 $70,035 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$501 $1,103 Short-term debt1,550 695 Accounts payable2,307 1,781 Regulatory liabilities714 852 Taxes accrued579 535 Accrued interest337 280 Dividends payable355 314 Derivative instruments31 37 Operating lease liabilities110 227 Other605 635 Total current liabilities7,089 6,459 Deferred credits and other liabilitiesDeferred income taxes6,004 5,319 Regulatory liabilities6,277 6,010 Asset retirement obligations3,888 3,713 Derivative instruments67 77 Customer advances129 146 Pension and employee benefit obligations365 477 Operating lease liabilities788 867 Finance lease liabilities1,262 60 Other61 69 Total deferred credits and other liabilities18,841 16,738 Commitments and contingenciesCapitalizationLong-term debt31,832 27,316 Common stock - 1,000,000,000 shares authorized of $2.50 par value; 623,600,715 and 574,365,598 shares outstanding at Dec." **Prior (2025):** (amounts in millions, except share and per share) Dec. 3120242023AssetsCurrent assetsCash and cash equivalents$179 $129 Accounts receivable, net1,249 1,315 Accrued unbilled revenues832 853 Inventories666 711 Regulatory assets561 611 Derivative instruments114 104 Prepaid taxes72 52 Prepayments and other652 294 Total current assets4,325 4,069 Property, plant and equipment, net57,198 51,642 Other assetsNuclear decommissioning fund and other investments3,896 3,599 Regulatory assets2,849 2,798 Derivative instruments72 76 Operating lease right-of-use assets1,060 1,217 Other635 678 Total other assets8,512 8,368 Total assets$70,035 $64,079 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$1,103 $552 Short-term debt695 785 Accounts payable1,781 1,668 Regulatory liabilities852 528 Taxes accrued535 557 Accrued interest280 251 Dividends payable314 289 Derivative instruments37 74 Operating lease liabilities227 226 Other635 722 Total current liabilities6,459 5,652 Deferred credits and other liabilitiesDeferred income taxes5,319 4,885 Deferred investment tax credits40 60 Regulatory liabilities6,010 5,827 Asset retirement obligations3,713 3,218 Derivative instruments77 86 Customer advances146 167 Pension and employee benefit obligations477 469 Operating lease liabilities867 1,038 Other89 148 Total deferred credits and other liabilities16,738 15,898 Commitments and contingenciesCapitalizationLong-term debt27,316 24,913 Common stock - 1,000,000,000 shares authorized of $2.50 par value; 574,365,598 and 554,941,703 shares outstanding at Dec. 31, 2024 and Dec. 31, 2023, respectively1,436 1,387 Additional paid in capital9,601 8,465 Retained earnings8,553 7,858 Accumulated other comprehensive loss(68)(94)Total common stockholders' equity19,522 17,616 Total liabilities and equity$70,035 $64,079 See Notes to Consolidated Financial Statements Common stock - 1,000,000,000 shares authorized of $2.50 par value; 574,365,598 and 554,941,703 shares outstanding at Dec. 31, 2024 and Dec. 31, 2023, respectively 51 51 51 Table of Contents Table of Contents **Current (2026):** (amounts in millions, except share and per share) Dec. 3120252024AssetsCurrent assetsCash and cash equivalents$274 $179 Accounts receivable, net1,330 1,249 Accrued unbilled revenues880 832 Inventories761 666 Regulatory assets529 561 Derivative instruments165 114 Prepayments and other1,075 724 Total current assets5,014 4,325 Property, plant and equipment, net65,639 57,198 Other assetsNuclear decommissioning fund and other investments4,389 3,896 Regulatory assets2,998 2,849 Derivative instruments54 72 Operating lease right-of-use assets893 1,060 Finance lease right-of-use assets1,348 111 Other1,036 524 Total other assets10,718 8,512 Total assets$81,371 $70,035 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$501 $1,103 Short-term debt1,550 695 Accounts payable2,307 1,781 Regulatory liabilities714 852 Taxes accrued579 535 Accrued interest337 280 Dividends payable355 314 Derivative instruments31 37 Operating lease liabilities110 227 Other605 635 Total current liabilities7,089 6,459 Deferred credits and other liabilitiesDeferred income taxes6,004 5,319 Regulatory liabilities6,277 6,010 Asset retirement obligations3,888 3,713 Derivative instruments67 77 Customer advances129 146 Pension and employee benefit obligations365 477 Operating lease liabilities788 867 Finance lease liabilities1,262 60 Other61 69 Total deferred credits and other liabilities18,841 16,738 Commitments and contingenciesCapitalizationLong-term debt31,832 27,316 Common stock - 1,000,000,000 shares authorized of $2.50 par value; 623,600,715 and 574,365,598 shares outstanding at Dec. 31, 2025 and Dec. 31, 2024, respectively1,559 1,436 Additional paid in capital12,906 9,601 Retained earnings9,207 8,553 Accumulated other comprehensive loss(63)(68)Total common stockholders' equity23,609 19,522 Total liabilities and equity$81,371 $70,035 See Notes to Consolidated Financial Statements Common stock - 1,000,000,000 shares authorized of $2.50 par value; 623,600,715 and 574,365,598 shares outstanding at Dec. 31, 2025 and Dec. 31, 2024, respectively 50 50 50 Table of Contents Table of Contents --- ## Modified: Pending Regulatory Proceedings **Key changes:** - Removed sentence: "Michigan Electric Rate Case - In July 2024, NSP-Wisconsin filed a Michigan electric rate case with the MPSC." - Removed sentence: "In December 2024, the MPSC approved NSP-Wisconsin's settlement agreement." - Removed sentence: "The settlement order includes an electric rate increase of $1.75 million in 2025 and a step increase of $0.55 million in 2026, based on a ROE of 9.8% and an equity ratio of 50%." - Removed sentence: "Wisconsin 2025 Stay-Out Proposal - In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW." - Removed sentence: "In December 2024, the PSCW approved NSP-Wisconsin's filing, which offsets $27 million in electric deficiencies and $3 million in natural gas deficiencies by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects." **Prior (2025):** Michigan Electric Rate Case - In July 2024, NSP-Wisconsin filed a Michigan electric rate case with the MPSC. In December 2024, the MPSC approved NSP-Wisconsin's settlement agreement. The settlement order includes an electric rate increase of $1.75 million in 2025 and a step increase of $0.55 million in 2026, based on a ROE of 9.8% and an equity ratio of 50%. Wisconsin 2025 Stay-Out Proposal - In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. In December 2024, the PSCW approved NSP-Wisconsin's filing, which offsets $27 million in electric deficiencies and $3 million in natural gas deficiencies by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects. Excess Liability Insurance Deferral - In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. A PSCW decision is expected in the third quarter of 2025. NSP System **Current (2026):** Excess Liability Insurance Deferral - In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. The PSCW issued a written approval in November 2025 and authorized recovery of the deferral over 2026 and 2027 in the Wisconsin Electric and Natural Gas Rate Case described below. Wisconsin Electric and Natural Gas Rate Case - In March 2025, NSP-Wisconsin filed a request with the PSCW for a multi-year electric and natural gas rate increase. Both the electric and natural gas rate requests were based on forward-looking 2026 and 2027 test years, with a 10.0% ROE and an equity ratio of 53.5%. In December 2025, the PSCW issued final written approval on NSP-Wisconsin's request, with a final rate increase of $126 million for the electric utility ($68 million in 2026, with an incremental $58 million in 2027) and $22 million for the natural gas utility ($18 million in 2026, with an incremental $4 million in 2027), based on a ROE of 9.8% and an equity ratio of 52.5%. (Millions of Dollars)ElectricNatural GasNSP-Wisconsin's filed two-year rate request$151 $24 PSCW decision:Capital investments(8)(1)ROE adjustment(7)(1)O&M expenses(5)(1)Nuclear decommissioning accrual update (a)(6) - Excess liability insurance deferral recovery4 1Other, net(3) - Total revenue change$126 $22 --- *Data sourced from SEC EDGAR. Last updated 2026-06-01.*