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 earnings per share, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings: (Millions of Dollars) 2023 2022 GAAP net income $ 1,771 $ 1,736 Loss on Comanche Unit 3 litigation 35 — Workforce reduction expenses 72 — Less: tax effect of adjustments (27) — Ongoing earnings $ 1,851 $ 1,736 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 Twelve Months Ended Dec. 31, 2022 Diluted Earnings (Loss) Per Share GAAP Diluted EPS Impact of Adjustments Ongoing Diluted EPS NSP-Minnesota $ 1.23 $ — $ 1.23 PSCo 1.33 — 1.33 SPS 0.64 — 0.64 NSP-Wisconsin 0.23 — 0.23 Earnings from equity method investments — WYCO 0.04 — 0.04 Regulated utility (a) 3.47 — 3.47 Xcel Energy Inc. and Other (0.29) — (0.29) Total (a) $ 3.17 — $ 3.17 (a) Amounts may not add due to rounding. Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a $34 million loss due to a jury verdict in Denver County District Court awarding CORE lost power damages and other costs. PSCo intends to file an appeal of this decision. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings. See Note 12 to the consolidated financial statements for further information. 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. Total workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023. Given the non-recurring nature of this item, it has been excluded from ongoing earnings. See Note 15 to the consolidated financial statements for further information. 26 Table of Contents Results of Operations Diluted EPS for Xcel Energy at Dec. 31: 2023 2022 Diluted Earnings (Loss) Per Share GAAP Diluted EPS GAAP Diluted EPS NSP-Minnesota $ 1.28 $ 1.23 PSCo 1.26 1.33 SPS 0.70 0.64 NSP-Wisconsin 0.25 0.23 Earnings from equity method investments — WYCO 0.04 0.04 Regulated utility (a) 3.52 3.47 Xcel Energy Inc. and Other (0.31) (0.29) GAAP Diluted EPS (a) 3.21 3.17 Loss on Comanche Unit 3 litigation 0.05 — Workforce reduction expenses 0.09 — Ongoing Diluted EPS (a) $ 3.35 $ 3.17 (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. 2023 Comparison with 2022 Xcel Energy — GAAP diluted earnings were $3.21 per share compared to $3.17 per share in 2022 and ongoing diluted earnings were $3.35 per share in 2023, compared with $3.17 per share in 2022. The increase in ongoing earnings per share was driven by increased recovery of infrastructure investments, higher sales and demand and lower O&M expenses, partially offset by higher depreciation and interest charges and unfavorable weather. 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 $0.05 per share and ongoing earnings increased $0.09 per share for 2023 compared to 2022. The change to ongoing earnings was driven by increased recovery of electric infrastructure investments, partially offset by increased interest charges and unfavorable weather. PSCo — GAAP earnings decreased $0.07 per share and ongoing earnings was flat for 2023 compared to 2022. Ongoing earnings primarily reflects higher recovery of infrastructure investment and lower O&M expenses, which were partially offset by increased depreciation, interest charges and unfavorable weather. SPS — GAAP earnings increased $0.06 per share and ongoing earnings increased $0.07 per share for 2023 compared to 2022. Ongoing earnings were largely impacted by regulatory rate outcomes, sales growth, partially offset by increased depreciation, interest charges and unfavorable weather. NSP-Wisconsin — GAAP and ongoing earnings increased $0.02 per share for 2023 compared to 2022. The increase in ongoing earnings was primarily a result of higher recovery of electric infrastructure investment, partially offset by unfavorable weather and, higher depreciation, O&M expenses and interest charges. Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from EIP funds equity method investments. Fluctuations from 2022 levels were largely attributable to increased interest rates. Changes in Diluted EPS Components significantly contributing to changes in EPS: 2023 vs. 2022 Diluted Earnings (Loss) Per Share Dec. 31 GAAP and ongoing diluted EPS — 2022 $ 3.17 Components of change — 2023 vs. 2022 Higher electric revenues, net of electric fuel and purchased power 0.07 Lower O&M expenses 0.06 Lower conservation and demand side management expenses (offset in electric revenues) 0.06 Higher other income (expense) 0.05 Lower taxes (other than income taxes) 0.04 Higher natural gas revenues, net of cost of natural gas sold and transported 0.03 Higher interest expense (0.14) Higher depreciation and amortization (0.05) Workforce reduction expenses (0.09) Loss on Comanche Unit 3 litigation (0.05) Other (net) 0.06 GAAP diluted EPS — 2023 $ 3.21 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Ongoing diluted EPS — 2023 $ 3.35 ROE for Xcel Energy and its utility subsidiaries: 2023 2022 ROE GAAP ROE Ongoing ROE GAAP and Ongoing ROE NSP-Minnesota 8.82 % 9.11 % 8.76 % PSCo 7.32 7.77 8.23 SPS 9.80 9.98 9.36 NSP-Wisconsin 10.38 10.67 10.57 Operating Companies 8.45 8.79 8.74 Xcel Energy 10.33 10.79 10.76 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 decoupling mechanisms in Colorado (mechanism expired in September 2023) and electric sales true-up mechanisms in Minnesota and gas decoupling mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in those jurisdictions. 27 Table of Contents Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2023 vs. Normal 2022 vs. Normal 2023 vs. 2022 HDD (7.3) % 6.5 % (12.9) % CDD 5.2 23.7 (13.8) THI 16.0 5.6 9 Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions: 2023 vs. Normal 2022 vs. Normal 2023 vs. 2022 Retail electric $ 0.013 $ 0.138 $ (0.125) Decoupling and sales true-up (0.007) (0.061) 0.054 Electric total $ 0.006 $ 0.077 $ (0.071) Firm natural gas (0.010) 0.037 (0.047) Decoupling $ 0.013 $ — $ 0.013 Gas total $ 0.003 $ 0.037 $ (0.034) Total $ 0.009 $ 0.114 $ (0.105) Sales — Sales growth (decline) for actual and weather-normalized sales: 2023 vs. 2022 NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy Actual Electric residential (0.5) % (4.0) % (3.0) % (2.6) % (2.3) % Electric C&I (1.1) (1.9) 5.2 (0.5) 0.5 Total retail electric sales (0.9) (2.6) 3.6 (1.1) (0.3) Firm natural gas sales (12.0) (1.5) N/A (12.6) (5.7) 2023 vs. 2022 NSP-Minnesota PSCo SPS NSP-Wisconsin Xcel Energy Weather-normalized Electric residential 1.0 % 1.6 % 1.1 % 0.1 % 1.2 % Electric C&I (1.1) (0.4) 5.3 (0.4) 1.0 Total retail electric sales (0.4) 0.3 4.5 (0.3) 1.0 Firm natural gas sales — 2.3 N/A (0.4) 1.4 Annual weather-normalized electric sales growth (decline) • NSP-Minnesota — Residential sales increased due to a 1.2% increase in customers outpacing declines in use per customer. The decline in C&I sales was due to lower use per customer, particularly due to weakness in the manufacturing sector compared to prior year. • PSCo — Residential sales increased due to increased use per customer and a 1.3% increase in customers. The decline in C&I sales was attributable to decreased use per customer, primarily in the manufacturing sector. • SPS — Residential sales growth was primarily attributable to a 0.7% increase in customers and increased use per customer. C&I sales increased due to higher use per customer, primarily driven by the energy sector. • NSP-Wisconsin — The C&I sales decline was associated with lower use per customer, experienced primarily in the transportation and manufacturing sectors. Annual weather-normalized natural gas sales growth (decline) • Natural gas sales reflect 1.2% residential and 0.7% C&I customer growth and an increase in C&I use per customer at PSCo. Partially offsetting these increases were lower use per residential customer in all jurisdictions. Electric Margin Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. These price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes. Electric Revenues, Fuel and Purchased Power and Electric Margin (Millions of Dollars) 2023 2022 Electric revenues $ 11,446 $ 12,123 Electric fuel and purchased power (4,278) (5,005) Electric margin $ 7,168 $ 7,118 28 Table of Contents Change in Electric Margin (Millions of Dollars) 2023 vs. 2022 Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI) $ 100 Non-fuel riders 89 Sales and demand (a) 57 Wholesale transmission (net) 28 Revenue recognition of the Texas rate case surcharge (b) (85) Estimated impact of weather (net of decoupling/sales true-up) (51) Conservation and demand side management (offset in expense) (43) PTCs flowed back to customers (offset by lower ETR) (28) Other (net) (17) Total increase $ 50 (a) Sales excludes weather impact, net of partial decoupling in Colorado (mechanism expired in September 2023) and sales true-up mechanism in Minnesota . (b) The decline in electric margin is due to the recognition of the Texas rate case outcome in the second quarter of 2022, which was largely offset by recognition of previously deferred costs. Natural Gas Margin Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms. Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin (Millions of Dollars) 2023 2022 Natural gas revenues $ 2,645 $ 3,080 Cost of natural gas sold and transported (1,456) (1,910) Natural gas margin $ 1,189 $ 1,170 Change in Natural Gas Margin (Millions of Dollars) 2023 vs. 2022 Regulatory rate outcomes (CO, WI, MI) $ 50 Estimated impact of weather (net of decoupling) (25) Other (net) (6) Total increase $ 19 Non-Fuel Operating Expenses and Other Items O&M Expenses — O&M expenses decreased $47 million in 2023, primarily due to the impact of management cost containment efforts, the exit of our appliance repair services business and the change in deferred costs associated with the Texas Electric Rate Cases (offset in Electric revenues), offset by higher bad debt expenses, the impact of inflationary pressures, including labor, and timing of unplanned maintenance at generating plants. Depreciation and Amortization — Depreciation and amortization increased $35 million for the year, primarily related to system expansion, offset by the change in deferred costs associated with the Texas Electric Rate Case and depreciation life extensions implemented in the Minnesota Electric Rate Case. Taxes (other than Income Taxes) —Taxes (other than income taxes) decreased $31 million in 2023, primarily due to lower property tax expense (lower tax rates in Minnesota offset by increase in Colorado) and deferrals related to the Minnesota Electric Rate Case and Texas Electric Rate Case. Other Income (Expense) — Other income (expense) increased $35 million for the year, primarily related to rabbi trust performance, which is primarily offset in employee benefit cost in O&M expenses. Interest Charges — Interest charges increased $102 million in 2023. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates. Xcel Energy Inc. and Other Results Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars) 2023 2022 Xcel Energy Inc. financing costs $ (174) $ (153) Venture Holdings (a) 3 5 Xcel Energy Inc. taxes and other results (2) (12) Total Xcel Energy Inc. and other costs $ (173) $ (160) (Diluted Earnings (Loss) Per Share) 2023 2022 Xcel Energy Inc. financing costs $ (0.32) $ (0.28) Venture Holdings (a) 0.01 0.01 Xcel Energy Inc. taxes and other results — (0.02) Total Xcel Energy Inc. and other costs $ (0.31) $ (0.29) (a) Amounts include gains or losses associated with EIP investments. Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries. 2022 Comparison with 2021 A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2021 to Dec. 31, 2022 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 2022, which was filed with the SEC on Feb. 23, 2023. 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. 29 Table of Contents 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. 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 (a) Recovers costs of conservation and DSM programs. Customer Protection Mechanisms MISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, and deferred tax asset refund 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). GUIC 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 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 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. Transmission Cost Recovery Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. (a) 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. Pending and Recently Concluded Regulatory Proceedings 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate request was based on a ROE of 10.2%, a 52.5% equity ratio and forward test years. In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota revised its rate request to $498 million over three years. 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 October 2023, the MPUC denied NSP-Minnesota’s request for reconsideration of certain aspects of the decision. NSP-Minnesota filed an appeal of the decision to the Minnesota Court of Appeals in November 2023. 2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of approximately $59 million, or 9.6%. The request is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In Dec. 2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024). Next steps in the procedural schedule are expected to be as follows: • Intervenor direct testimony: April 19, 2024 • Rebuttal testimony: May 24, 2024 • Evidentiary hearings: July 10-12, 2024 • ALJ Report: October 28, 2024 • MPUC Order Due: March 14, 2025 30 Table of Contents 2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC for an annual natural gas rate increase of approximately $8 million, or 9.4%. The filing is based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forecast test year with rate base of approximately $168 million. NSP-Minnesota requested interim rates, subject to refund, of approximately $8 million to be implemented on March 1, 2024. 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 PI 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 at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives 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 PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the current operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054. In October 2023, the MPUC issued an order approving NSP-Minnesota’s application for a CON for additional spent fuel storage (existing Independent Spent Fuel Storage Installation) at the Monticello Nuclear Power Generating Plant to allow continued operation of the Monticello Plant until 2040. 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. Michigan Public Service Commission 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. 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. Recently Concluded Regulatory Proceedings Wisconsin Rate Case — In 2023, NSP-Wisconsin filed a Wisconsin rate case seeking a revised electric increase of $25 million and a natural gas increase of $7 million. The filing was based on a 2024 forecast test year, a ROE of 10.25%, an equity ratio of 52.5% and a forecasted average net rate base of approximately $2.1 billion for the electric utility and $284 million for the natural gas utility. 31 Table of Contents In December 2023, the PSCW approved a ROE of 9.8% and an equity ratio of 52.5% as well as a rate increase of approximately $1 million for the electric utility. Adjustments to NSP-Wisconsin’s rate request included removal of a proposed residential affordability program and other earnings neutral adjustments and fuel and purchased power costs. The PSCW also approved a $5 million rate increase for the natural gas utility in 2024. The new rates were implemented on Jan. 1, 2024. NSP System Pending and Recently Concluded Regulatory Proceedings 2022 Upper Midwest IRP Resource Acquisition — Following the MPUC’s approval of NSP-Minnesota and NSP-Wisconsin’s latest IRP in April 2022, NSP-Minnesota and NSP-Wisconsin have been engaged in multiple resource acquisition processes and proceedings to meet the need identified in the IRP for the NSP System. • In August 2022, NSP-Minnesota and NSP-Wisconsin jointly filed an RFP seeking at least 900 MW of solar or solar plus storage capacity. In May 2023, NSP-Minnesota filed a recommended portfolio, which proposed an additional 250 MW of self-build solar generation at the site of our retiring Sherco coal units and a 100 MW solar PPA located in Wisconsin as part of the resource plan RFP. In September 2023, the MPUC approved the request for 350 MW, subject to a cost cap based on projected costs for the Sherco solar project. • In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of 800 MW of firm dispatchable resources. In January 2024, NSP-Minnesota and other companies submitted proposed resources. NSP-Minnesota expects a decision by the fourth quarter of 2024. • In July 2023, NSP-Wisconsin issued an RFP seeking approximately 650 MW of solar and/or solar plus storage development assets that will be developed in the 2027-2029 timeframe to replace the capacity from the retiring King Generating Station. The RFP closed in September 2023 and bids are being evaluated. • In October 2023, NSP-Minnesota issued an RFP seeking approximately 1,200 MW of wind development assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023 and the NSP-Minnesota expects to file for approval of recommended projects by mid-2024. 2024 Upper Midwest Energy Plan — In February 2024, NSP-Minnesota filed its resource plan with the MPUC. Key components of the plan include the following: • Reduced carbon emissions by more than 80%, potentially up to 88%, by 2030. • Extends the operation of Prairie Island and Monticello nuclear plants through the early 2050s. • Adds 3,600 MW of new wind and solar resources by 2030. • Adds 600 MW of battery energy storage by 2030. • Adds more than 2,200 MW of dispatchable resources by 2030. NSP-Minnesota anticipates a MPUC decision in 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. 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. 32 Table of Contents 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. Decoupling Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes (pilot program ended Sept. 2023, with amortization of previously deferred amounts expected through 2026). DSM Cost Adjustment Recovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals. ECA Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly. 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. Transportation Electrification Plan Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. Pending and Recently Concluded Regulatory Proceedings Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate case seeking a revised net increase of $253 million. The total request reflected a $303 million increase, which includes $50 million of authorized costs previously recovered through various rider mechanisms. The request was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test year with a 2023 average rate base of $11.3 billion. In September 2023, the CPUC approved a settlement between PSCo and various parties, which included the following terms: • Retail revenue increase (excluding rider roll-ins) of $95 million (2.96%), based on a 2022 historic test year using year-end rate base with forward looking known and measurable adjustments. • Weighted-average cost of capital of 6.95% (based on 55.69% equity ratio and 9.3% ROE). • Termination of the revenue decoupling pilot. • Continuation of previously authorized trackers and deferrals. Rates became effective in September 2023. Colorado Resource Plan — In August 2022, the CPUC approved a settlement for the Colorado Resource Plan, which provides for an expected carbon reduction and the retirement of PSCo’s remaining coal plant by the end of 2030. In September 2023 (updated in October 2023), PSCo filed its recommended Preferred Portfolio of resources, which proposed a total of 7,521 MW of generation resources, including 4,716 owned MW and 2,805 purchased power MW. The filing also included several other alternative portfolios. In December 2023, the CPUC approved an alternative portfolio of 5,835 MW. The decision provides an opportunity to assess timing and levels of incremental renewable resources in the Just Transition Plan filing expected to be submitted by June 1, 2024. Approved portfolio includes the following resources: Generation Resource (in MW) Company Owned PPAs Total Wind Resources 1,325 375 1,700 Solar 858 760 1,618 Storage 500 1,348 1,848 Natural Gas 450 219 669 Total 3,133 2,702 5,835 PSCo expects to invest approximately $4.8 billion in generation resources under the alternative portfolio for the benefit of its customers and achieving the state’s clean energy goals. The CPUC did not approve the May Valley to Longhorn Transmission Line, which was estimated at $250 million. In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a two-way sharing measure related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in the written order and related proceedings throughout 2024. In February 2024, PSCo filed an ARRR to seek approval for an updated portfolio, reflecting inclusion of certain back-up bids and clarifications of the application of PIMs. 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, or an approximately 9.5% increase in the average residential customer bill. The request is based on a 2023 test year, a 10.25% ROE, an equity ratio of 55% and a $4.2 billion retail rate base which includes projected capital additions through Dec. 31, 2023. PSCo has requested a proposed effective date of Nov. 1, 2024. PSCo has proposed to defer collection of the increased rates until Feb. 15, 2025 (following the expiration of the rider to recover Winter Storm Uri costs) to mitigate customer bill impacts, with revenues for the deferred period collected over a 12-month period beginning on that date. The request supports fundamental infrastructure investments to serve customers, consistent with PSCo’s obligation to provide safe, reliable service while enabling PSCo to continue to be a leader of the clean energy transition in partnership with the CPUC to achieve clean heat goals. Revenue Request (millions of dollars) Changes since 2022 rate case: Plant related investments (a) $ 145 Operations and maintenance, amortization and other expenses 23 Property tax expense 10 Sales growth (7) Total base revenue request $ 171 (a) Includes approximately $32 million as a result of the increase in ROE from 9.2% to 10.25%. ECA Fuel Recovery — In December 2022, PSCo filed to recover $123 million of under-recovered 2022 fuel costs over two quarters. In December 2022, the CPUC found that the $123 million should be removed from the proposed ECA rates, and required PSCo to file a separate application to recover these costs. In 2023, PSCo submitted interim ECA filings to recover $70 million and $25 million, respectively, of the 2022 under-recovered costs. 33 Table of Contents In the third quarter, PSCo and CPUC Staff filed a settlement allowing for collection of the remaining amount, which after final adjustments was $37 million. In December 2023, the ALJ issued a recommended decision approving the settlement in full. Recovery of costs is expected to begin in the second quarter of 2024. Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed and 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 management plan, 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 are 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 by Jan. 1, 2025. The CPUC issued a request for initial comments on a potential mechanism under which gas utilities would share a percentage, subject to an annual cap, of cost changes in the GCA. A formal rulemaking is expected to commence in the first half of 2024. 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. Energy Markets — PSCo joined the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in an organized wholesale market. Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand 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. 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. Generation Cost Recovery Rider Allows recovery of investment in power generation facilities outside of a base rate case proceeding. Purchased Power Capacity Cost Recovery Factor Allows recovery of purchased power capacity costs not included in Texas rates. 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 2022 New Mexico Electric Rate Case — In 2022, SPS filed a New Mexico electric rate case seeking a revised revenue increase of $75 million. The request was based on a ROE of 10.75%, an equity ratio of 54.7%, a future test year ending June 30, 2024 and rate base of $2.4 billion. 34 Table of Contents In October 2023, the NMPRC approved a settlement between SPS, NMPRC Staff, and various parties, which included the following terms: • Base rate revenue increase of $33 million, based on the filed future test year. • ROE of 9.5%. • Equity ratio of 54.7%. • The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028. Rates went into effect in October 2023. 2023 Texas Electric Rate Case — In 2023, SPS filed a Texas electric rate case seeking an increase in base rate revenue of $158 million (14%). The request was based on a ROE of 10.65%, an equity ratio of 54.6% and rate base of $3.6 billion. SPS requested a surcharge from July 13, 2023 through the effective date of new base rates. In December 2023, SPS, PUCT Staff and intervenors filed a black box settlement. Key terms include: • 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. • The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028. A PUCT decision is expected in the first half of 2024. SPS and LP&L Termination — SPS and LP&L were parties to a 25-year, 170 MW partial requirements contract serving LP&L. In May 2021, SPS and LP&L finalized a settlement which terminated the contract upon LP&L’s move from the SPP to the ERCOT. Based on the approved de-escalation clause, LP&L paid SPS $66 million in January 2024 to the benefit of SPS’ remaining customers. 2022 All-Source RFP — In July 2023, SPS filed for approval of CCN for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. A decision from PUCT and NMPRC is expected in mid-2024. The second portion of the portfolio includes a November 2023 filing for the approval of PPAs including 48 MW of battery energy storage and 230 MW of existing gas generation. Regulatory decisions on these PPA agreements are expected in Q3 2024. New Mexico Resource Plan — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and secures replacement energy and capacity for retiring resources. Based on load forecast scenarios, SPS’ initial IRP modeling projects a total resource need ranging from approximately 5,300 MW to 10,200 MW by 2030. Upon acceptance of the IRP, SPS expects to issue an RFP for new generation in mid-2024. The RFP will be evaluated in the latter half of 2024 with portfolio selection expected in early 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. 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, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. Inflationary pressures, labor shortages, and the impact of geopolitical events have further exacerbated these disruptions. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work. Additionally, certain products, components, and equipment, particularly in renewables categories, originate in countries that could face tariffs, fines, or restrictions from government or other regulatory bodies and present a cost and supply risk until there is sufficient capacity and supply base with adequate capacity to meet US needs. Electric Meters and Transformers Supply chain issues associated with semiconductors delayed the availability of AMI meters, which led to a reduced number of meters deployed in 2022. Xcel Energy saw significant improvement in meter availability in 2023 and we expect normal conditions in 2024 and going forward. Xcel Energy expects to complete AMI meter deployment in 2025. Additionally, the availability of certain transformers is an industry-wide issue that has significantly impacted and in some cases resulted in delays to projects and new customer connections. Proposed governmental actions related to transformer efficiency standards may compound these delays in the future. Xcel Energy continues to seek alternative suppliers and prioritize work plans to mitigate the impacts of supply constraints. Solar Resources In August 2023, the U.S. Department of Commerce completed its anti-circumvention investigation. It concluded that CSPV solar panels and cells imported from Malaysia, Vietnam, Thailand, and Cambodia would be subject to incremental tariffs ranging from 50% to 250%. These countries account for more than 80% of CSPV panel imports. 35 Table of Contents An interim stay on tariffs remains in effect until June 2024. Many significant solar projects have resumed with modified costs and projected in-service dates, including the Sherco Solar facility in Minnesota and certain PPAs in PSCo. Further policy action, a change in the interim stay of tariffs, or other restrictions on solar imports (e.g., due to implementation of the Uyghur Forced Labor Protection Act) or disruptions in solar imports from key suppliers could impact project timelines and costs. New Technology and Government Grants Hydrogen Hub Grant In October 2023, t he DOE selected the Heartland Hydrogen Hub, including multiple clean hydrogen projects from Xcel Energy, for award negotiations to receive up to $925 million. The Heartland Hydrogen Hub is one of seven selected to receive DOE funding. The hub includes Xcel Energy, Marathon Petroleum Corporation and TC Energy, in collaboration with the University of North Dakota’s Energy & Environmental Resource Center, to produce and use low-carbon hydrogen at commercial scale in Minnesota, Wisconsin, South Dakota, North Dakota and Montana. The hub aims to reduce carbon emissions by more than 1 million metric tons per year. Xcel Energy expects to receive a large portion of the federal award for its projects within the hub, subject to negotiations. In its application, Xcel Energy proposed investing up to $2 billion over a decade for clean hydrogen producing equipment and infrastructure, representing 75% of full program costs for the company’s portion of the hub. Project detailed design will begin after the Heartland Hydrogen Hub finishes award negotiations. Project development will likely continue through 2035. Form Energy Long Duration Storage Grant In September 2023, the DOE awarded Xcel Energy a $70 million grant to support our two 10 MW, 100-hour battery pilots with Form Energy. Xcel Energy expects to develop a 10 MW 100-hour-battery storage unit at the Sherco retiring coal plant site in Minnesota and the Comanche retiring coal plant site in Colorado. Combined with grants from Breakthrough Energy’s Catalyst Fund, Xcel Energy has secured $90 million to support these pilots, which will reduce the costs of the projects for our customers. Long duration energy storage systems are critical to achieve 100% carbon free generation and strengthen the grid from the variability of renewable energy. Wildfire/Extreme Weather Grant In October 2023, the DOE awarded Xcel Energy $100 million to support projects to mitigate the threat of wildfires and ensure resiliency of the grid through extreme weather. Xcel Energy plans to match the grant with $140 million of investment. The projects will take a number of steps to boost grid resiliency, including adding fire-resistant coatings to 6,000 wood poles, improving equipment safety features in power lines and electric vehicle chargers in high fire risk conditions, moving high-risk distribution circuits underground, and enhancing vegetation management. They will also build on current programs using emerging technology, such as drones aided by artificial intelligence that inspect power lines for safety, wind strength testing, satellite identification of trees that pose a risk and modeling software to predict how fires would spread. Joint Targeted Interconnection Queue (JTIQ) Grant In October 2023, the DOE awarded a $464 million grant to Xcel Energy and several other utilities for five JTIQ projects. The projects are part of a collaboration between MISO and SPP that will help to fund the construction of high-voltage transmission lines that improve reliability and resolve constraints in the transmission system for up to 30 gigawatts of new generation. Xcel Energy is part of two of these project awards. 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, 2023 and 2022, Xcel Energy had regulatory assets of $3.4 billion and $3.9 billion, respectively and regulatory liabilities of $6.4 billion and $6.0 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, 2023, 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. 36 Table of Contents 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. At Dec. 31, 2023, Xcel Energy set the rate of return on assets used to measure pension costs at 6.93%, which is unchanged from the rate set at Dec. 31, 2022. The rate of return used to measure postretirement health care costs is 5.00% at Dec. 31, 2023, which is unchanged from the rate set in 2022. Xcel Energy’s pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan’s funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios. Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.49% and 5.54% at Dec. 31, 2023, respectively. This represents a 31 basis point and 26 basis point decrease, respectively, from 2022. 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 2023 pension costs: Pension Costs (Millions of Dollars) +1% -1% Rate of return (a) $ (10) $ 26 Discount rate (a) 3 8 (a) These costs include the effects of regulation. 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, 2023, the initial medical trend cost claim assumptions for Pre-65 was 6.5% and Post-65 was 5.5%. 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 2023 were $50 million and will remain relatively consistent in future years, with the exception of 2024, when Xcel Energy plans on making a higher contributions as a result of the Voluntary Retirement Program offering in 2023. Investment returns were more than the assumed levels in 2023 and 2021, but were less than the assumed levels in 2022. 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 13 years in 2023). Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $59 million in 2024 and $61 million in 2025, while the actual pension costs were $74 million in 2023 and $114 in 2022. The expected decrease in 2024 is primarily due to reductions in the effects or regulations. Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2021 - 2024: • $100 million in January 2024. • $50 million in 2023. • $50 million in 2022. • $131 million in 2021. 37 Table of Contents 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, $13 million and $15 million during 2023, 2022 and 2021, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $11 million during 2024. 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. • In 2021, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2021 pension settlement accounting expense. Escrow accounting treatment was also approved for ongoing pension and other post-employment benefit expenses, including settlement charges. • 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 that adjusts the annual post-retirement benefits amount to zero in order to match the amount collected in rates. • 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. 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. 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 asset. The amounts recorded for AROs related to future nuclear decommissioning were $2.1 billion in 2023 and $2.2 billion in 2022. 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. The 2022 - 2024 Nuclear Decommissioning Study and Assumptions were approved by the MPUC in August 2022. The MPUC ordered the next triennial decommissioning study be filed by December 1, 2024, allowing for four years between filings. 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 approved retirement dates which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively). In April 2022, the Company received approval from the MPUC, in the Integrated Resource Plan, to pursue extending the operating life of the Monticello Nuclear Generating Plant by ten years from 2030 to 2040. This life extension is subject to NRC approval of Monticello’s nuclear license extension request. The retirement dates of the Prairie Island Unit 1 and Unit 2 remain unchanged, 2033 and 2034 respectively. The estimated timing of the decommissioning activities is based upon the 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 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 3.2% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors calculated by Goldman Sachs Asset Management. 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. 38 Table of Contents 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, 2023. See Note 12 to the consolidated financial statements for further information. Loss Contingencies – Marshall Fire The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire 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 an unfavorable outcome and the ability to make a reasonable estimate of the amount of loss. 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 the wildfire, the extent and magnitude of potential damages, and the status of investigations and legal proceedings are considered. See Note 12 to 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. 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, 2023: 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) $ 1 $ (3) $ (3) $ — $ (5) NSP-Minnesota (b) (1) (8) (6) (1) (16) PSCo (a) — 1 2 — 3 PSCo (b) (10) 6 2 — (2) $ (10) $ (4) $ (5) $ (1) $ (20) 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) $ — $ — $ 9 $ 8 $ 17 PSCo (b) 4 — — — 4 $ 4 $ — $ 9 $ 8 $ 21 (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) 2023 2022 Fair value of commodity trading net contracts outstanding at Jan. 1 $ (10) $ (33) Contracts realized or settled during the period (2) (15) Commodity trading contract additions and changes during the period 13 38 Fair value of commodity trading net contracts outstanding at Dec. 31 $ 1 $ (10) 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 $4 million at Dec. 31, 2023 and $8 million at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances. Xcel Energy’s’ 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 2023 $ — $ — $ 1 $ — 2022 2 1 5 — 39 Table of Contents Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2024 through 2027 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. NSP-Minnesota is scheduled to take delivery of approximately 29% of its average enriched nuclear material requirements from Russia through 2030. Given the evolving situation in Ukraine and its global impacts, we have entered into additional new contracts that cover potential supply interruptions of nuclear material from Russia. 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 $9 million and $8 million in 2023 and 2022, 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, 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 a decrease in credit exposure of $24 million. At Dec. 31, 2022, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $56 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $47 million. 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 — 2022 $ 3,932 Components of change — 2023 vs. 2022 Higher net income 35 Non-cash transactions 88 Changes in working capital 900 Changes in net regulatory and other assets and liabilities 372 Cash provided by operating activities — 2023 $ 5,327 Net cash provided by operating activities increased by $1,395 million for 2023 as compared to 2022. The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables. Investing Cash Flows (Millions of Dollars) Twelve Months Ended Dec. 31 Cash used in investing activities — 2022 $ (4,653) Components of change — 2023 vs. 2022 Increased capital expenditures (1,216) Other investing activities (57) Cash used in investing activities — 2023 $ (5,926) Net cash used in investing activities increased by $1,273 million for 2023 as compared to 2022. The increase in capital expenditures was largely due to continued system expansion. Financing Cash Flows (Millions of Dollars) Twelve Months Ended Dec. 31 Cash provided by financing activities — 2022 $ 666 Components of change — 2023 vs. 2022 Higher debt issuances, net of repayments 80 Lower proceeds from issuance of common stock (52) Higher dividends paid to shareholders (80) Other financing activities 3 Cash provided by financing activities — 2023 $ 617 Net cash provided by financing activities decreased by $49 million for 2023 as compared to 2022. The decrease was largely related to the amount/timing of debt issuances and repayments. See Note 5 to the consolidated financial statements for further information. 40 Table of Contents 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. Material Cash Requirements and Other Commitments Payments Due by Period (as of Dec. 31, 2023) (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 $ 43,659 $ 1,567 $ 3,631 $ 3,564 $ 34,897 Finance lease obligations 218 10 19 16 173 Operating leases obligations (a) 1,520 277 509 313 421 Unconditional purchase obligations (b) (c) 4,022 1,429 1,267 686 640 Other long-term obligations, including current portion (d) 57 18 27 12 — Other short-term obligations 591 591 — — — Short-term debt 785 785 — — — Total contractual cash obligations $ 50,852 $ 4,677 $ 5,453 $ 4,591 $ 36,131 (a) Included in operating lease obligations are $244 million, $461 million, $269 million and $259 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were 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 minimum payments related to SPS’ extension of a non-lease PPA that otherwise expires in 2026, pending PUCT and NMPRC approvals to extend the agreement to 2039. Approval processes are expected to conclude in 2024. (d) Primarily consists of contracts for information technology services. Capital Expenditures — Base capital expenditures and incremental capital forecasts: Actual Base Capital Forecast (Millions of Dollars) By Regulated Utility 2023 2024 2025 2026 2027 2028 2024 - 2028 Total PSCo $ 2,310 $ 3,300 $ 5,230 $ 4,320 $ 3,620 $ 2,730 $ 19,200 NSP-Minnesota 2,370 2,660 2,970 2,380 2,500 2,540 13,050 SPS 750 910 780 660 870 830 4,050 NSP-Wisconsin 450 570 600 570 600 650 2,990 Other (a) 330 (20) (300) 10 10 10 (290) Total base capital expenditures $ 6,210 $ 7,420 $ 9,280 $ 7,940 $ 7,600 $ 6,760 $ 39,000 (a) Other category includes intercompany transfers for safe harbor wind turbines. Actual Base Capital Forecast (Millions of Dollars) By Function 2023 2024 2025 2026 2027 2028 2024 - 2028 Total Electric transmission $ 1,320 $ 1,710 $ 2,020 $ 2,450 $ 2,850 $ 2,470 $ 11,500 Electric distribution 1,730 1,770 1,960 2,200 2,200 2,470 10,600 Renewables 350 1,500 2,910 940 240 20 5,610 Electric generation 780 940 1,290 1,050 1,060 600 4,940 Natural gas 780 740 680 630 620 570 3,240 Other 1,250 760 420 670 630 630 3,110 Total base capital expenditures $ 6,210 $ 7,420 $ 9,280 $ 7,940 $ 7,600 $ 6,760 $ 39,000 The base plan does not include potential renewable generation additions at the NSP System, SPS and PSCo, which could result in additional capital expenditures of approximately $5 billion. 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 (e.g., federal clean energy and 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. 41 Table of Contents Financing for Capital Expenditures through 2028 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Current estimated financing plans of Xcel Energy for 2024 through 2028 (includes the impact of tax credit transferability): (Millions of Dollars) Funding Capital Expenditures Cash from operations (a) $ 22,000 New debt (b) 13,000 Equity through the DRIP and benefit program 500 Other equity 3,500 Base capital expenditures 2024 - 2028 $ 39,000 Maturing Debt $ 3,780 (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 2024, Xcel Energy announced an increase in the annual dividend of 11 cents per share, which represents an increase of 5.3%. 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, 2023 Dec. 31, 2022 Fair value of pension assets $ 2,690 $ 2,685 Projected pension obligation (a) 2,943 2,871 Funded status $ (253) $ (186) (a) Excludes non-qualified plan of $12 million and $11 million at Dec. 31, 2023 and 2022, respectively. Pension Assumptions 2023 2022 Discount rate 5.49 % 5.80 % Expected long-term rate of return 6.93 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 — 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. As of Feb. 20, 2024, 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 $ 486 $ 1,014 $ 2 $ 1,016 PSCo 700 258 442 6 448 NSP-Minnesota 700 273 427 10 437 SPS 500 99 401 3 404 NSP-Wisconsin 150 43 107 8 115 Total $ 3,550 $ 1,159 $ 2,391 $ 29 $ 2,420 (a) Credit facilities expire in September 2027. (b) Includes outstanding commercial paper and letters of credit. 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, 2023 and 2022, Xcel Energy had approximately 555 million shares and 550 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. 42 Table of Contents Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect the following: Issuer Security Amount (Millions of Dollars) Anticipated Timing Expected Tenor Xcel Energy Inc. Senior Unsecured Notes $ 900 First Quarter 10 Year PSCo First Mortgage Bonds 1,200 Second Quarter 10 Year and 30 Year NSP-Minnesota First Mortgage Bonds 700 First Quarter 30 Year SPS First Mortgage Bonds 550 Second Quarter 30 Year NSP-Wisconsin First Mortgage Bonds 400 Second Quarter 30 Year Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its at-the-market program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. See Note 5 to the consolidated financial statements for further information. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share. (a) Key assumptions as compared with 2023 actual levels unless noted: • Constructive outcomes in all pending rate case and regulatory proceedings. • Normal weather patterns for the remainder of the year. • Weather-normalized retail electric sales are projected to increase 2% to 3%. • Weather-normalized retail firm natural gas sales are projected to be flat. • Capital rider revenue is projected to increase $70 million to $80 million (net of PTCs). • O&M expenses are projected to increase 1% to 2%. • Depreciation expense is projected to increase approximately $250 million to $260 million. • Property taxes are projected to increase $50 million to $60 million. • Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income. • AFUDC - equity is projected to increase $45 million to $55 million. • ETR is projected to be ~(4%) to (6%) . The negative ETR is largely offset by PTCs flowing back to customers in the capital riders and fuel mechanisms and is largely earnings neutral. The projected ETR does not reflect the potential impact of nuclear PTCs, which are also expected to flow back to customers. (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 5% to 7% based off of a 2023 actual ongoing earnings base of $3.35 per share. • Deliver annual dividend increases of 5% to 7%. • 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.