XCEL ENERGY INC 10-K

ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Non-GAAP Financial Measures The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that is adjusted from measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures. Ongoing ROE Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results. Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS) GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS 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) 2024 2023 GAAP net income $ 1,936 $ 1,771 Loss on Comanche Unit 3 litigation — 35 Workforce reduction expenses — 72 Sherco Unit 3 2011 outage refunds 47 — 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, 2024 Diluted Earnings (Loss) Per Share GAAP Diluted EPS Impact of Adjustments Ongoing Diluted EPS NSP-Minnesota $ 1.41 $ 0.06 $ 1.47 PSCo 1.39 — 1.39 SPS 0.70 — 0.70 NSP-Wisconsin 0.24 — 0.24 Earnings from equity method investments — WYCO 0.03 — 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, 2023 Diluted Earnings (Loss) Per Share GAAP Diluted EPS Impact of Adjustments Ongoing Diluted EPS NSP-Minnesota $ 1.28 $ 0.04 $ 1.32 PSCo (a) 1.26 0.08 1.33 SPS 0.70 0.01 0.71 NSP-Wisconsin 0.25 — 0.25 Earnings from equity method investments — WYCO 0.04 — 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. 25 Table of Contents Results of Operations Diluted EPS for Xcel Energy at Dec. 31: Diluted Earnings (Loss) Per Share 2024 2023 NSP-Minnesota $ 1.41 $ 1.28 PSCo 1.39 1.26 SPS 0.70 0.70 NSP-Wisconsin 0.24 0.25 Earnings from equity method investments — WYCO 0.03 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 refunds 0.06 — 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 2023 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 EPS Components significantly contributing to changes in 2024 EPS compared with 2023: Diluted Earnings (Loss) Per Share Twelve Months Ended Dec. 31 GAAP diluted EPS — 2023 $ 3.21 Components of change — 2024 vs. 2023 Electric regulatory rate outcomes and riders 0.73 Higher other income, net 0.16 Natural gas regulatory rate outcomes and riders 0.14 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 refunds 0.06 Ongoing diluted EPS — 2024 $ 3.50 ROE for Xcel Energy and its utility subsidiaries: 2024 2023 ROE GAAP ROE Ongoing ROE GAAP ROE Ongoing ROE NSP-Minnesota 9.07 % 9.46 % 8.82 % 9.11 % PSCo 7.63 7.63 7.32 7.77 SPS 9.57 9.57 9.80 9.98 NSP-Wisconsin 8.98 8.98 10.38 10.67 Utility Subsidiaries 8.55 8.69 8.45 8.79 Xcel Energy 10.42 10.61 10.33 10.79 Statement of Income Analysis 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 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. Normal 2023 vs. Normal 2024 vs. 2023 HDD (15.4) % (7.3) % (9.8) % CDD 28.1 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. Normal 2023 vs. Normal 2024 vs. 2023 Retail electric $ (0.008) $ 0.013 $ (0.021) Decoupling and sales true-up 0.047 (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. 2023 NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy Actual Electric 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. 2023 NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy Weather-normalized Electric residential 0.2 % 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-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy Weather-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 Revenues 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. 2023 Recovery 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 riders 169 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 Table of Contents Natural Gas Revenues Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. (Millions of Dollars) 2024 vs. 2023 Recovery 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 riders 8 Other, net 18 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 Items 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 Results Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars) 2024 2023 Xcel 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) 2024 2023 Xcel 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 Regulation The 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. 28 Table of Contents NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of Jurisdiction Regulatory Body / RTO Additional Information MPUC 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. NDPSC 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. SDPUC 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. FERC 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. MISO 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. DOT Pipeline safety compliance. Minnesota Office of Pipeline Safety Pipeline safety compliance. Recovery Mechanisms Mechanism Additional Information CIP Rider Recovers 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 Mechanisms MISO 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. Decoupling Measures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers. FCA Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota). Gas Utility Infrastructure Cost Rider Recovers 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 Rider Recovers costs for investments in generation in South Dakota. Purchased Gas Adjustment Provides 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 Rider Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota. Renewable Energy Rider Recovers cost of renewable generation in North Dakota. RES Rider Recovers cost of renewable generation in Minnesota. Sales True-up Mitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric Rider Recovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota. Transmission Cost Recovery Rider Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings 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 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 Operations 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 Jurisdiction Regulatory Body / RTO Additional Information PSCW Retail 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. MPSC Retail 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. FERC Wholesale 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. MISO NSP-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. DOT Pipeline safety compliance. 30 Table of Contents Recovery Mechanisms Mechanism Additional Information Annual Fuel Cost Plan NSP-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 Factors NSP-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 A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services. Wisconsin Energy Efficiency Program The primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from customers. Pending Regulatory Proceedings 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 Pending and Recently Concluded Regulatory Proceedings Resource Acquisition — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the resource plan, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition. In February 2025, the MPUC verbally approved the terms of the settlement agreement, including: • The selection of the company owned 420 MW Lyon County combustion turbine. • The selection of the company owned 300 MW 4-hour Sherco battery energy storage system. • Multiple PPAs to proceed to the negotiation stage. • The addition of 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line. • Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s. Additionally, the MPUC approved life extensions of the Red Wing and Mankato RDF plants to 2037 and ordered NSP-Minnesota to file a proposed tariff for customers with super-large load, largely data centers, by July 15, 2025. NSP-Minnesota will file additional RFPs for approved resource needs beginning in late 2025 or early 2026. NSP-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 summer 2025. • 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. Bids are currently under evaluation; NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second half of 2025. Purchased Power and Transmission Services 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 Table of Contents Wholesale and Commodity Marketing Operations 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 Summary of Regulatory Agencies / RTO and Areas of Jurisdiction Regulatory Body / RTO Additional Information on Regulatory Authority CPUC 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. FERC 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. RTO 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. DOT Pipeline safety compliance. Recovery Mechanisms Mechanism Additional Information Colorado Energy Plan Adjustment Recovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill. DSM Cost Adjustment Recovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals. Electric Commodity Adjustment Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. PTCs earned for owned wind generation are returned to customers. FCA PSCo 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. GCA Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. Purchased Capacity Cost Adjustment Recovers purchased capacity payments. RES Adjustment Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. Steam Cost Adjustment Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly. Transmission Cost Adjustment Recovers 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 Plan Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. Pending and Recently Concluded Regulatory Proceedings Colorado 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: 32 Table of Contents (MW) Base Plan Low Load Wind 7,250 2,800 Solar 3,077 1,200 Natural gas combustion turbine 1,575 1,400 Storage (long duration) 1,600 — Other storage 450 — Total 13,952 5,400 The procedural schedule is as follows: • Answer testimony: April 18, 2025 • Rebuttal testimony: May 23, 2025 • Settlement deadline: June 2, 2025 • Hearing: June 10-20, 2025 • Statements of position: July 14, 2025 A CPUC decision on the resource plan is expected by the fall of 2025 (Phase I) with the competitive solicitation for resource additions expected in early 2026. Wildfire Mitigation Plan — In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion. A CPUC decision is expected in the third quarter of 2025. The WMP integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following: • Situational awareness — Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring. • Operational mitigations – Enhanced powerline safety settings and PSPS. • System resiliency — Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management. • Customer support — Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates. In February 2025, six of the nine intervenors filed answer testimony in the proceeding. Intervenors provided a range of recommendations related to both the scope of proposed work and the cost recovery proposal. The remaining procedural schedule is as follows: • Rebuttal testimony: March 21, 2025 • Settlement deadline: April 11, 2025 • Hearing: May 5-15, 2025 • Decision deadline: Aug. 28, 2025 Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines). In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the GCA rate. As a result, costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit deferred as a reserve against future cost increases. The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers. In December 2024, the CPUC adopted final rules applicable to PSCo’s natural gas utility that would assign to the Company four percent of the change in the price per MMbtu of natural gas compared to the three-year average, subject to rolling 12-month cap based on a percentage of rate base, currently estimated at $7 million. The rules require PSCo to make a filing to implement the mechanism within sixty days of becoming effective, expected later in 2025. In December 2024, the CPUC also adopted rules for electric utilities but did not adopt a specific PIM framework, which will be further considered through additional proceedings in 2025. Colorado Senate Bill 24-218 — In May 2024, Colorado Senate Bill 24-218 was signed into law. The bill includes a suite of policy changes to accelerate investment in electric distribution, including a framework to develop distribution planning and performance requirements and the opportunity for current cost recovery through a rider for distribution investments. In July 2024 and December 2024, the CPUC approved PSCo’s request to collect $17 million and $48 million through a rider, over the remainder of 2024 and 2025, respectively, subject to true-up, associated with forecasted capital investments covered by the new legislation. Excess Liability Insurance Deferral — In August 2024, PSCo filed a request with the CPUC to establish a tracker to defer differences in excess liability insurance premiums after the October 2024 policy renewal (reflecting significantly rising premiums of approximately $40 million, largely associated with wildfire risks throughout the United States) and amounts currently recovered. In January 2025, the CPUC approved a one-year deferral aligned with the current insurance policy year. Cost recovery for incremental insurance premiums will be reviewed in a future rate case. Purchased Power and Transmission Service Providers 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 Operations PSCo 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. 33 Table of Contents SPS Summary of Regulatory Agencies / RTO and Areas of Jurisdiction Regulatory Body / RTO Additional Information PUCT Retail 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. NMPRC Retail electric operations, retail rates and services and the construction of transmission or generation. Reviews Integrated Resource Plans for meeting future energy needs. FERC Wholesale 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 Markets SPS 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. DOT Pipeline safety compliance. Recovery Mechanisms Mechanism Additional Information Advanced Metering System Surcharge Recovers costs incurred in deployment of the Advanced Metering System in Texas. Consulting Fee Rider Recovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT. Distribution Cost Recovery Factor Recovers distribution costs not included in rates in Texas. Electric Vehicle Rider Recovers costs of the Transportation Electrification Plan in New Mexico. Energy Efficiency Cost Recovery Factor Recovers costs for energy efficiency programs in Texas. Energy Efficiency Rider Recovers costs for energy efficiency programs in New Mexico. Fixed Fuel and Purchased Recovery Factor Provides 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 Clause Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. Grid Modernization Rider Recovers costs incurred in the implementation of Grid Modernization Components in New Mexico. Renewable Portfolio Standards Recovers deferred costs for renewable energy programs in New Mexico. Transmission Cost Recovery Factor Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates. Wholesale Fuel and Purchased Energy Cost Adjustment SPS 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. Pending and Recently Concluded Regulatory Proceedings 2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%). Interim rates went into effect on Feb. 1, 2024. In April 2024, the PUCT approved a black box settlement between SPS and intervening parties, which reflect the following terms: • A base rate increase of $65 million effective back to July 13, 2023. • A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required. • The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028. • Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses. In July 2024, SPS filed to surcharge the final under-recovered amount of $37 million. This will be largely offset by previously deferred costs. In February 2025, the PUCT approved the surcharge. 2022 All-Source RFP — In July 2023, SPS filed for approval of a CPCN for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. The NMPRC approved the projects in May 2024. In July 2024, the PUCT approved the solar projects and denied the battery project. The PUCT’s approval included minimum production and PTC guarantees. New Mexico Resource Plan (IRP) — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS’ projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP. In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors. The RFP portfolio selection is expected in May 2025. SPS is expected to file for a CON for the recommended portfolio in the summer of 2025. The PUCT and NMPRC are expected to rule on the portfolio in 2026. Texas System Resiliency Plan — In December 2024, SPS filed its Texas SRP with the PUCT. Consistent with PUCT requirements, SPS’ proposed plan discusses resiliency-related risks and the five measures that have been designed to help SPS prevent, withstand, mitigate or more promptly recover from resiliency events, including wildfire. The SRP includes the following measures: • Distribution overhead hardening — Replacing and reinforcing key components of the distribution overhead system. • Distribution system protection modernization — Installing enhanced reclosers, communications equipment and replacing substation relay panels and breakers. • Communication modernization — Building out a private LTE network, installing fiber optic cable and adding remote terminal units. • Operational flexibility — Procuring mobile substation equipment and installing additional switching devices. • Wildfire mitigation — Weather stations, modeling, deploying artificial intelligence and vegetation management. 34 Table of Contents The plan covers 2025-2028 and includes the following total spend: (Millions of Dollars) Capital O&M Total Distribution overhead hardening $ 253 $ — $ 253 Distribution system protection modernization 92 — 92 Communication modernization 112 — 112 Operational flexibility 44 — 44 Wildfire mitigation 20 17 37 Total $ 521 $ 17 $ 538 The procedural schedule is as follows: • Intervenor testimony: February 28, 2025 • Staff testimony: March 7, 2025 • Rebuttal testimony: March 17, 2025 • Hearing: March 25-26, 2025 A PUCT decision is expected in the summer of 2025. Purchased Power Arrangements and Transmission Service Providers SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers. Natural Gas SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance. Wholesale and Commodity Marketing Operations SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. Other 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 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 Table of Contents Excess Liability Insurance Coverage 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. Critical Accounting Policies and Estimates Preparation 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 Accounting Xcel 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 Accruals 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 Benefits 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 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 Decommissioning 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 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 – Wildfires 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. Derivatives, Risk Management and Market Risk 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 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 Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value NSP-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 Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value NSP-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) 2024 2023 Fair 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. 31 Average High Low 2024 $ — $ — $ 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. 39 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 Measurements Derivative 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 Resources Cash Flows Operating Cash Flows (Millions of Dollars) Twelve Months Ended Dec. 31 Cash provided by operating activities — 2023 $ 5,327 Components of change — 2024 vs. 2023 Higher net income 165 Non-cash transactions 222 Changes in deferred taxes 284 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. 31 Cash used in investing activities — 2023 $ (5,926) Components of change — 2024 vs. 2023 Increased capital expenditures (1,510) Other investing activities 8 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. 31 Cash provided by financing activities —2023 $ 617 Components of change — 2024 vs. 2023 Higher long-term debt issuances, net of repayments 1,512 Higher proceeds from issuance of common stock 847 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 Requirements Xcel 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. 40 Table of Contents Material Cash Requirements and Other Commitments Payments Due by Period (as of Dec. 31, 2024) (Millions of Dollars) Total Less than 1 Year 1 to 3 Years 3 to 5 Years After 5 Years Long-term debt, principal and interest payments $ 50,915 $ 2,292 $ 3,316 $ 3,846 $ 41,461 Finance lease obligations 208 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 obligations 632 632 — — — Short-term debt 695 695 — — — Total contractual cash obligations $ 57,645 $ 5,352 $ 5,008 $ 4,538 $ 42,747 (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 Utility 2024 2025 2026 2027 2028 2029 2025 - 2029 Total PSCo $ 3,180 $ 5,820 $ 5,190 $ 3,940 $ 3,780 $ 3,550 $ 22,280 NSP-Minnesota 2,830 3,240 2,500 2,830 2,080 2,570 13,220 SPS 1,100 1,400 1,540 1,280 1,040 1,040 6,300 NSP-Wisconsin 560 640 650 690 660 670 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 (a) Other category includes intercompany transfers for safe harbor wind turbines. Actual Base Capital Forecast (Millions of Dollars) By Function 2024 2025 2026 2027 2028 2029 2025 - 2029 Total Electric distribution $ 2,220 $ 2,570 $ 3,000 $ 3,400 $ 3,320 $ 3,540 $ 15,830 Electric transmission 1,720 2,260 2,860 2,740 2,390 2,310 12,560 Renewables 1,130 3,360 1,400 260 — — 5,020 Electric generation 960 1,210 1,150 910 580 620 4,470 Natural gas 780 800 680 690 630 620 3,420 Other 840 800 750 750 650 750 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. 41 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 Expenditures Cash from operations (a) $ 25,320 New debt (b) 15,180 Equity through the DRIP and benefit program 500 Other equity 4,000 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 Arrangements 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, 2024 Dec. 31, 2023 Fair 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 Assumptions 2024 2023 Discount rate 5.88 % 5.49 % Expected long-term rate of return 7.13 6.93 Capital Sources 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) Available Cash Liquidity Xcel Energy Inc. $ 1,500 $ 660 $ 840 $ 25 $ 865 PSCo 700 101 599 10 609 NSP-Minnesota 700 375 325 7 332 SPS 500 255 245 7 252 NSP-Wisconsin 150 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. 42 Table of Contents Planned Financing Activity — Xcel Energy’s 2025 financing plans reflect the following: Issuer Security Amount (Millions of Dollars) Expected Tenor Anticipated Timing Xcel Energy Inc. Senior Unsecured Notes $ 1,000 10 Year First Quarter PSCo First Mortgage Bonds 2,000 10 Year & 30 Year Second & Third Quarter NSP-Minnesota First Mortgage Bonds 1,100 10 Year & 30 Year First & Third Quarter SPS First Mortgage Bonds 450 30 Year Second Quarter NSP-Wisconsin First Mortgage Bonds 250 30 Year Second Quarter See Note 5 to the consolidated financial statements for further information. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives Xcel Energy 2025 Earnings Guidance — Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share. (a) Key assumptions as compared with 2024 actual levels unless noted: • Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans. • Normal weather patterns for the year. • Weather-normalized retail electric sales are projected to increase ~3%. • Weather-normalized retail firm natural gas sales are projected to increase ~1%. • Capital rider revenue is projected to increase $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 RISK See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.