{ "ticker": "XEL", "company": "Xcel Energy Inc.", "filing_type": "10-K", "year_current": "2025", "year_prior": "2024", "summary": { "added": 10, "removed": 10, "modified": 68, "unchanged": 48, "total_current": 126, "total_prior": 126 }, "source": "SEC EDGAR", "url": "https://riskdiff.com/xel/2025-vs-2024/", "markdown_url": "https://riskdiff.com/xel/2025-vs-2024/index.md", "json_url": "https://riskdiff.com/xel/2025-vs-2024/index.json", "generated": "2026-06-01", "ai_summary": null, "risks": [ { "status": "ADDED", "current_title": "We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.", "prior_title": null, "current_body": "Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks." }, { "status": "ADDED", "current_title": "Our utilities have physical and financial risks associated with wildfires.", "prior_title": null, "current_body": "In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Wildfires could jeopardize Xcel Energy’s electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. 16 16 16 Table of Contents Table of Contents We have programs in place to mitigate the physical and financial risks associated with wildfires; however, Xcel Energy’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when Xcel Energy follows its procedures and implements its wildfire mitigation initiatives.Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows.We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. We have programs in place to mitigate the physical and financial risks associated with wildfires; however, Xcel Energy’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when Xcel Energy follows its procedures and implements its wildfire mitigation initiatives.Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows.We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted. We have programs in place to mitigate the physical and financial risks associated with wildfires; however, Xcel Energy’s wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. Wildfires can occur even when Xcel Energy follows its procedures and implements its wildfire mitigation initiatives. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts could potentially exceed our coverage and negatively impact our results of operations, financial condition or cash flows." }, { "status": "ADDED", "current_title": "2024 vs. 2023", "prior_title": null, "current_body": "2024 vs. 2023 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(0.1)%0.7 %(1.5)%(1.8)%(0.1)%Electric C&I(2.0)(1.4)9.0 (1.8)1.5 Total retail electric sales(1.4)(0.7)7.1 (1.8)1.0 Firm natural gas sales(1.7)— N/A(3.1)(0.7)Annual weather-normalized and leap year adjusted electric sales growth (decline)•NSP-Minnesota — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector.•PSCo — Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining. •SPS — Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining. •NSP-Wisconsin — Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.Annual weather-normalized and leap year adjusted natural gas sales growth (decline)•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions. Electric RevenuesElectric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of electric fuel and purchase power(479)PTCs flowed back to customers (offset by lower ETR)(302)Wholesale generation revenues(96)Sherco Unit 3 2011 outage refunds(47)Regulatory rate outcomes (MN, CO, TX, and NM)372 Non-fuel riders169 Conservation and demand side management (offset in expense)102 Estimated impact of weather (net of sales true-up)24 Other, net(42)Total decrease$(299) 2024 vs. 2023 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(0.1)%0.7 %(1.5)%(1.8)%(0.1)%Electric C&I(2.0)(1.4)9.0 (1.8)1.5 Total retail electric sales(1.4)(0.7)7.1 (1.8)1.0 Firm natural gas sales(1.7)— N/A(3.1)(0.7)" }, { "status": "ADDED", "current_title": "Additional Information", "prior_title": null, "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025." }, { "status": "ADDED", "current_title": "Pending Regulatory Proceedings", "prior_title": null, "current_body": "Michigan Electric Rate Case — In July 2024, NSP-Wisconsin filed a Michigan electric rate case with the MPSC. In December 2024, the MPSC approved NSP-Wisconsin’s settlement agreement. The settlement order includes an electric rate increase of $1.75 million in 2025 and a step increase of $0.55 million in 2026, based on a ROE of 9.8% and an equity ratio of 50%. Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. In December 2024, the PSCW approved NSP-Wisconsin’s filing, which offsets $27 million in electric deficiencies and $3 million in natural gas deficiencies by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects. Excess Liability Insurance Deferral – In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. A PSCW decision is expected in the third quarter of 2025. NSP System" }, { "status": "ADDED", "current_title": "Additional Information", "prior_title": null, "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025." }, { "status": "ADDED", "current_title": "Excess Liability Insurance Coverage", "prior_title": null, "current_body": "Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states." }, { "status": "ADDED", "current_title": "Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$— $— $20 $— $20", "prior_title": null, "current_body": "NSP-Minnesota (b) (a)Prices actively quoted or based on actively quoted prices. (b)Prices based on models and other valuation methods. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31: (Millions of Dollars)20242023Fair value of commodity trading net contracts outstanding at Jan. 1$1 $(10)Contracts realized or settled during the period— (2)Commodity trading contract additions and changes during the period(3)13 Fair value of commodity trading net contracts outstanding at Dec. 31$(2)$1 A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2024 and $4 million at Dec. 31, 2023. The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2024$— $— $1 $— 2023— — 1 — Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:" }, { "status": "ADDED", "current_title": "Commitments and Contingencies - Wildfires – Refer to Note 12 to the consolidated financial statements", "prior_title": null, "current_body": "Critical Audit Matter Description As a result of wildfires that have occurred in the Company's service territory in Colorado and Texas, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with the 2021 Marshall Wildfire and the 2024 Smokehouse Creek Fire Complex (the \"Wildfires\"). In evaluating this exposure, the Company is required to determine whether the likelihood of loss for each of the Wildfires is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the Wildfires, investigations, and discovery associated with lawsuits. A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts. A current asset for claim amounts that are recoverable from insurance related to a loss contingency is recorded when it is probable the claim will be recovered. We identified contingencies from the Wildfires and the related disclosures as a critical audit matter due to the significant judgments made by management to determine the probability of loss and estimate the probable losses and insurance recoveries. Auditing the reasonableness of management's judgments, estimates and disclosures related to the Wildfires required a high degree of auditor judgment and increased extent of audit effort. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to management's judgments regarding the probability of loss, estimated losses and insurance recoveries, and related disclosures for contingencies related to the Wildfires included the following, among others: •We tested the effectiveness of controls over (1) the Company's determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable; (2) the determination of the significant assumptions used in estimating the amount of probable loss and probable insurance recoveries; and (3) the disclosures related to the Wildfires. •We evaluated management's judgments related to whether a loss was probable or reasonably possible from the Wildfires by inquiring of management and the Company's external and internal legal counsel. We also evaluated the potential impact of information gained through the Company and third parties' investigations into the cause of the Wildfires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management's assertions. •We evaluated management’s methodologies for assessing estimates of loss and recording a probable loss through inquiries with management and external and internal legal counsel and we tested the significant assumptions, including payments to settle claims, used in the estimates of probable loss. •We read legal letters from the Company's external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures. •We evaluated management's judgments related to whether certain insurance recoveries were probable of collection by inquiring of management and the Company's internal legal counsel regarding the amounts of insurance recoveries recorded or disclosed. We obtained and inspected relevant insurance policies to evaluate coverages as well as communication between the Company and insurers. •We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures. /s/ DELOITTE & TOUCHE LLPMinneapolis, MinnesotaFebruary 27, 2025We have served as the Company’s auditor since 2002. /s/ DELOITTE & TOUCHE LLP 47 47 47 Table of Contents Table of Contents" }, { "status": "ADDED", "current_title": "Major classes of property, plant and equipment", "prior_title": null, "current_body": "(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Property, plant and equipment, netElectric plant$56,791 $52,494 Natural gas plant9,834 9,080 Common and other property3,515 3,190 Plant to be retired (a)1,793 2,055 CWIP4,720 2,873 Total property, plant and equipment76,653 69,692 Less accumulated depreciation(19,852)(18,399)Nuclear fuel3,491 3,337 Less accumulated amortization(3,094)(2,988)Property, plant and equipment, net$57,198 $51,642 Plant to be retired (a) (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process. Amounts are presented net of accumulated depreciation." }, { "status": "REMOVED", "current_title": null, "prior_title": "We are subject to environmental laws and regulations, with which compliance could be difficult and costly.", "prior_body": "We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations." }, { "status": "REMOVED", "current_title": null, "prior_title": "Electric Margin", "prior_body": "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." }, { "status": "REMOVED", "current_title": null, "prior_title": "Change in Electric Margin", "prior_body": "(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)$100 Non-fuel riders89 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 Sales and demand (a) Revenue recognition of the Texas rate case surcharge (b) (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." }, { "status": "REMOVED", "current_title": null, "prior_title": "Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin", "prior_body": "(Millions of Dollars)20232022Natural gas revenues$2,645 $3,080 Cost of natural gas sold and transported(1,456)(1,910)Natural gas margin$1,189 $1,170" }, { "status": "REMOVED", "current_title": null, "prior_title": "Change in Natural Gas Margin", "prior_body": "(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (CO, WI, MI)$50 Estimated impact of weather (net of decoupling)(25)Other (net)(6)Total increase$19" }, { "status": "REMOVED", "current_title": null, "prior_title": "Additional Information", "prior_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers 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 Proceedings2022 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" }, { "status": "REMOVED", "current_title": null, "prior_title": "Pending and Recently Concluded Regulatory Proceedings", "prior_body": "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 30 30 Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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 JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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 ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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. 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." }, { "status": "REMOVED", "current_title": null, "prior_title": "Additional Information", "prior_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers 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 Proceedings2022 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" }, { "status": "REMOVED", "current_title": null, "prior_title": "Supply Chain", "prior_body": "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 35 35 Table of Contents 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, the 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 GrantIn 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) GrantIn 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 EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 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. 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, the 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 GrantIn 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) GrantIn 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. 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." }, { "status": "REMOVED", "current_title": null, "prior_title": "4. Regulatory Assets and Liabilities", "prior_body": "Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2023Dec. 31, 2022 (a)Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$27 $1,106 $22 $1,069 Recoverable deferred taxes on AFUDCPlant lives— 332 — 292 Net AROs (b) 1, 12Various— 316 — 339 Excess deferred taxes — TCJA 7Various10 198 13 205 Depreciation differencesOne to 12 years17 189 17 193 Environmental remediation costs1, 12Various15 94 20 92 Deferred natural gas, electric, steam energy/fuel costsOne to three years239 80 581 299 Conservation programs (c)1One to two years19 54 16 36 Purchased power contract costsTerm of related contract4 40 10 36 PI extended power uprate11 years4 38 4 42 Benson biomass PPA termination and asset purchaseFive years10 36 10 45 Sales true-up and revenue decouplingOne to two years7 33 54 — State commission adjustments Plant lives1 32 1 33 Losses on reacquired debtTerm of related debt2 30 3 32 MISO capacity revenue trackerOne to two years36 26 — — Gas pipeline inspection and remediation costsOne to two years40 25 42 13 Contract valuation adjustments (d) 1, 10Term of related contract18 22 28 28 Nuclear refueling outage costs1One to two years43 19 30 12 Grid modernization costsOne to two years16 17 14 24 Renewable resources and environmental initiativesOne to two years38 5 50 6 OtherVarious65 106 144 75 Total regulatory assets$611 $2,798 $1,059 $2,871" }, { "status": "MODIFIED", "current_title": "We are subject to environmental laws and regulations, with which compliance could be difficult and costly.", "prior_title": "We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.", "similarity_score": 0.917, "confidence": "high", "key_changes": [ "Reworded sentence: \"We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.\"", "Reworded sentence: \"21 21 21 Table of Contents Table of Contents In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted.\"", "Reworded sentence: \"Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants.\"", "Reworded sentence: \"The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base.\"", "Reworded sentence: \"The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis.\"" ], "current_body": "We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods. While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. 21 21 21 Table of Contents Table of Contents In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.ITEM 1B — UNRESOLVED STAFF COMMENTSNone.ITEM 1C — CYBERSECURITYAs described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the enterprise has the ability to notify and update the Board of Directors in the event of a possible crisis situation.Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. As of Feb. 27, 2025 there have been no material cybersecurity incidents to report. In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.ITEM 1B — UNRESOLVED STAFF COMMENTSNone.ITEM 1C — CYBERSECURITYAs described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer. In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations. ITEM 1B — UNRESOLVED STAFF COMMENTS ITEM 1B — UNRESOLVED STAFF COMMENTS None. ITEM 1C — CYBERSECURITY As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program. Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer. Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the enterprise has the ability to notify and update the Board of Directors in the event of a possible crisis situation.Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. As of Feb. 27, 2025 there have been no material cybersecurity incidents to report. Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate. Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats. The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees. The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the enterprise has the ability to notify and update the Board of Directors in the event of a possible crisis situation. Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. As of Feb. 27, 2025 there have been no material cybersecurity incidents to report. 22 22 22 Table of Contents Table of Contents ITEM 2 — PROPERTIESVirtually all of the utility plant property of the utility subsidiaries is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 Prairie Island-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Dakota Range, SD, 72 UnitsWind2022298 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 Units Wind2008100 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 133 UnitsWind2010200 (d)Northern Wind-Murray County, MN, 37 UnitsWind202392 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Rock Aetna-Murray County, MN, 8 UnitsWind202220 (d)Solar:Sherco Solar 1-Becker, MN, 63 unitsSolar2024223 Total8,623 (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota’s ownership of 59%.(c)RDF is made from municipal solid waste.(d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%.NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%. ITEM 2 — PROPERTIESVirtually all of the utility plant property of the utility subsidiaries is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 Prairie Island-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Dakota Range, SD, 72 UnitsWind2022298 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 Units Wind2008100 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 133 UnitsWind2010200 (d)Northern Wind-Murray County, MN, 37 UnitsWind202392 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Rock Aetna-Murray County, MN, 8 UnitsWind202220 (d)Solar:Sherco Solar 1-Becker, MN, 63 unitsSolar2024223 Total8,623 (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota’s ownership of 59%.(c)RDF is made from municipal solid waste.(d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%. ITEM 2 — PROPERTIES ITEM 2 — PROPERTIES Virtually all of the utility plant property of the utility subsidiaries is subject to the lien of their respective first mortgage bond indentures. NSP-MinnesotaStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 Prairie Island-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Dakota Range, SD, 72 UnitsWind2022298 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 Units Wind2008100 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 133 UnitsWind2010200 (d)Northern Wind-Murray County, MN, 37 UnitsWind202392 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Rock Aetna-Murray County, MN, 8 UnitsWind202220 (d)Solar:Sherco Solar 1-Becker, MN, 63 unitsSolar2024223 Total8,623", "prior_body": "Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B — UNRESOLVED STAFF COMMENTSNone. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions. We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B — UNRESOLVED STAFF COMMENTS ITEM 1B — UNRESOLVED STAFF COMMENTS None. 22 22 22 Table of Contents Table of Contents ITEM 1C — CYBERSECURITYAs described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board of Directors conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report. ITEM 1C — CYBERSECURITYAs described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program.Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate. ITEM 1C — CYBERSECURITY As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business. The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which Xcel Energy has designed the cybersecurity control framework within its security risk program. Annually, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed. Xcel Energy’s cybersecurity policies, standards, practices and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer. Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate. Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats.The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board of Directors conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis.Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report. Management has assigned responsibility for the security risk program to the Chief Security Officer who has extensive experience in critical infrastructure protection, including multiple years of experience with the Department of Defense. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown cybersecurity threats. The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on a quarterly basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees. The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at each regular board meeting as well as at the ONES and Audit Committee meetings throughout the year. While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the Board of Directors conducts drills to practice its response in a possible emergency situation to ensure it is well prepared and positioned to perform in a possible crisis. Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. As of Feb. 21, 2024 there have been no material cybersecurity incidents to report. 23 23 23 Table of Contents Table of Contents ITEM 2 — PROPERTIESVirtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 (b)Unit 3Coal1987517 (c)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (d)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (e)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (e)Border-Rolette County, ND, 75 UnitsWind2015148 (e)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (e)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (e)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (e)Dakota Range, SD, 72 UnitsWind2022298 (e)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (e)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (e)Grand Meadow-Mower County, MN, 67 Units (f)Wind200899 (e)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (e)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (e)Mower-Mower County, MN, 43 UnitsWind202191 (e)Nobles-Nobles County, MN, 133 UnitsWind2010200 (e)Northern Wind-Murray County, MN, 37 Units (g)Wind202392 (e)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (e)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (e)Total9,081 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023.(c)Based on NSP-Minnesota’s ownership of 59%.(d)RDF is made from municipal solid waste.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota’s wind facilities had a weighted-average capacity factors of 43%.(f)Repowered in 2023.(g)Purchased in 2023.NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo’s wind facilities had a weighted-average capacity factors of 43%. ITEM 2 — PROPERTIESVirtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.NSP-MinnesotaStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 (b)Unit 3Coal1987517 (c)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (d)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (e)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (e)Border-Rolette County, ND, 75 UnitsWind2015148 (e)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (e)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (e)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (e)Dakota Range, SD, 72 UnitsWind2022298 (e)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (e)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (e)Grand Meadow-Mower County, MN, 67 Units (f)Wind200899 (e)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (e)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (e)Mower-Mower County, MN, 43 UnitsWind202191 (e)Nobles-Nobles County, MN, 133 UnitsWind2010200 (e)Northern Wind-Murray County, MN, 37 Units (g)Wind202392 (e)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (e)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (e)Total9,081 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023.(c)Based on NSP-Minnesota’s ownership of 59%.(d)RDF is made from municipal solid waste.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota’s wind facilities had a weighted-average capacity factors of 43%.(f)Repowered in 2023.(g)Purchased in 2023. ITEM 2 — PROPERTIES ITEM 2 — PROPERTIES Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures. NSP-MinnesotaStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:A.S. King-Bayport, MN, 1 UnitCoal1968511 Sherco-Becker, MNUnit 1Coal1976680 Unit 2Coal1977682 (b)Unit 3Coal1987517 (c)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RDFVarious36 (d)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005343 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018491 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas/Oil1974 - 2005454 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 8 UnitsNatural Gas/ Oil1972 - 1996276 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Hydro:Hennepin Island-Minneapolis, MN 5 UnitsHydro1954-19556 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (e)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (e)Border-Rolette County, ND, 75 UnitsWind2015148 (e)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (e)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (e)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (e)Dakota Range, SD, 72 UnitsWind2022298 (e)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (e)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (e)Grand Meadow-Mower County, MN, 67 Units (f)Wind200899 (e)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (e)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (e)Mower-Mower County, MN, 43 UnitsWind202191 (e)Nobles-Nobles County, MN, 133 UnitsWind2010200 (e)Northern Wind-Murray County, MN, 37 Units (g)Wind202392 (e)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (e)Rock Aetna - Murray County, MN, 8 UnitsWind202220 (e)Total9,081" }, { "status": "MODIFIED", "current_title": "We are subject to commodity risks and other risks associated with energy markets and energy production.", "prior_title": "We are subject to commodity risks and other risks associated with energy markets and energy production.", "similarity_score": 0.914, "confidence": "high", "key_changes": [ "Removed sentence: \"17 17 17 Table of Contents Table of Contents Failure to attract and retain a qualified workforce could have an adverse effect on operations.\"", "Removed sentence: \"The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning.\"", "Removed sentence: \"In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate.\"", "Removed sentence: \"Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business.\"", "Removed sentence: \"Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions.\"" ], "current_body": "A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity. A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations. We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.", "prior_body": "A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity. A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations. We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted. 17 17 17 Table of Contents Table of Contents Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery, our reputation and could introduce financial risk or risks of fines. Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Failure to attract and retain a qualified workforce could have an adverse effect on operations. The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery, our reputation and could introduce financial risk or risks of fines. Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows." }, { "status": "MODIFIED", "current_title": "6. Revenues", "prior_title": "6. Revenues", "similarity_score": 0.913, "confidence": "high", "key_changes": [ "Added sentence: \"31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 — 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 — — 645 Transmission648 — — 648 Other64 175 — 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec.\"" ], "current_body": "Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 — 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 — — 645 Transmission648 — — 648 Other64 175 — 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 — 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 — — 815 Transmission649 — — 649 Other63 156 — 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 — 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 — — 1,354 Transmission675 — — 675 Other97 178 — 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310", "prior_body": "Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 — 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 — — 815 Transmission649 — — 649 Other63 156 — 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 — 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 — — 1,354 Transmission675 — — 675 Other97 178 — 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310" }, { "status": "MODIFIED", "current_title": "A cybersecurity incident or security breach could have a material effect on our business.", "prior_title": "A cybersecurity incident or security breach could have a material effect on our business.", "similarity_score": 0.91, "confidence": "high", "key_changes": [ "Reworded sentence: \"To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.\"", "Reworded sentence: \"Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.\"", "Reworded sentence: \"Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions.\"", "Reworded sentence: \"We may be subject to climate change lawsuits.\"", "Reworded sentence: \"Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders.\"" ], "current_body": "We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. 20 20 20 Table of Contents Table of Contents Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions.", "prior_body": "We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. 20 20 20 Table of Contents Table of Contents Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency’s Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows. Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted. Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures." }, { "status": "MODIFIED", "current_title": "Natural Gas", "prior_title": "Natural Gas", "similarity_score": 0.906, "confidence": "high", "key_changes": [ "Reworded sentence: \"SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas.\"" ], "current_body": "SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance.", "prior_body": "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." }, { "status": "MODIFIED", "current_title": "We must rely on cash from our subsidiaries to make dividend payments.", "prior_title": "We must rely on cash from our subsidiaries to make dividend payments.", "similarity_score": 0.905, "confidence": "high", "key_changes": [ "Reworded sentence: \"Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends.\"", "Removed sentence: \"19 19 19 Table of Contents Table of Contents If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected.\"", "Removed sentence: \"Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met.\"", "Removed sentence: \"We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries.\"", "Removed sentence: \"Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates.\"" ], "current_body": "Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.Macroeconomic RisksEconomic conditions impact our business.Xcel Energy’s operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries.", "prior_body": "Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. 19 19 19 Table of Contents Table of Contents If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Macroeconomic RisksEconomic conditions impact our business.Xcel Energy’s operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest commercial and industrial customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operations. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Macroeconomic RisksEconomic conditions impact our business.Xcel Energy’s operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest commercial and industrial customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries." }, { "status": "MODIFIED", "current_title": "Station, Location and Unit at Dec. 31, 2024", "prior_title": "Station, Location and Unit at Dec. 31, 2023", "similarity_score": 0.902, "confidence": "high", "key_changes": [ "Reworded sentence: \"MW (a) (b) (b) (c) (c) (a)Summer 2024 net dependable capacity.\"", "Reworded sentence: \"(b)Harrington coal plant units 1-3 were retired in December 2024.\"", "Reworded sentence: \"31, 2024 SPS’ wind facilities had a weighted-average capacity factor of 50%.\"", "Reworded sentence: \"31, 2024: Conductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPSTransmission500 KV2,921 — — — 345 KV13,182 3,019 5,421 11,676 230 KV2,300 — 12,280 9,845 161 KV640 1,817 — — 138 KV— — 92 — 115 KV8,113 1,835 5,015 14,953 Less than 115 KV6,627 5,324 1,796 4,501 Total Transmission33,783 11,995 24,604 40,975 DistributionLess than 115 KV86,549 28,293 81,589 24,878 Total120,332 40,288 106,193 65,853 Electric utility transmission and distribution substations at Dec.\"", "Reworded sentence: \"The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 38 companies at year-end and is a broad measure of industry performance.Comparison of Five Year Cumulative Total Return** $100 invested on Dec.\"" ], "current_body": "MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota’s ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500", "prior_body": "MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota’s ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota’s wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo’s wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551" }, { "status": "MODIFIED", "current_title": "Station, Location and Unit at Dec. 31, 2024", "prior_title": "Station, Location and Unit at Dec. 31, 2023", "similarity_score": 0.895, "confidence": "high", "key_changes": [ "Reworded sentence: \"MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity.\"", "Reworded sentence: \"31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%.\"", "Reworded sentence: \"31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec.\"", "Reworded sentence: \"31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%.\"", "Reworded sentence: \"31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500\"" ], "current_body": "MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota’s ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500", "prior_body": "MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota’s ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota’s wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo’s wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551" }, { "status": "MODIFIED", "current_title": "We are subject to credit risks.", "prior_title": "We are subject to credit risks.", "similarity_score": 0.891, "confidence": "high", "key_changes": [ "Reworded sentence: \"Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense.\"", "Reworded sentence: \"In that event, our financial results could be adversely affected and we may incur losses.\"", "Reworded sentence: \"Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends.\"", "Reworded sentence: \"In that event, our financial results could be adversely affected and we may incur losses.\"", "Reworded sentence: \"We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants.\"" ], "current_body": "Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. 18 18 18 Table of Contents Table of Contents Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries. Federal tax law may significantly impact our business.Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.Macroeconomic RisksEconomic conditions impact our business.Xcel Energy’s operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy.We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.", "prior_body": "Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flow and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California Independent System Operator), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses. Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California Independent System Operator), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract." }, { "status": "MODIFIED", "current_title": "Public Utility Regulation", "prior_title": "Public Utility Regulation", "similarity_score": 0.891, "confidence": "high", "key_changes": [ "Removed sentence: \"29 29 29 Table of Contents Table of Contents Rates are designed to recover plant investment, operating costs and an allowed return on investment.\"", "Removed sentence: \"Our utility subsidiaries request changes in utility rates through commission filings.\"", "Removed sentence: \"Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates.\"", "Removed sentence: \"Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.\"", "Removed sentence: \"In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings.\"" ], "current_body": "The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations and credit quality. See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. 28 28 28 Table of Contents Table of Contents NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. NSP-Minnesota Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance.", "prior_body": "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 29 29 Table of Contents 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 JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers 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 Proceedings2022 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 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 JurisdictionRegulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance. 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." }, { "status": "MODIFIED", "current_title": "Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.", "prior_title": "Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.", "similarity_score": 0.888, "confidence": "high", "key_changes": [ "Reworded sentence: \"17 17 17 Table of Contents Table of Contents Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello.\"", "Reworded sentence: \"Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs, and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment.\"", "Added sentence: \"Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities.\"", "Added sentence: \"While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.\"", "Added sentence: \"Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations.\"" ], "current_body": "We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. 17 17 17 Table of Contents Table of Contents Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs, and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs, and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery.", "prior_body": "We are exposed to risk of employee or third-party contractor fraud or misconduct. All employees and members of the Board of Directors are subject to compliance with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to compliance with our Supplier Code of Conduct. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows. Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.Financial RisksOur profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery." }, { "status": "MODIFIED", "current_title": "Our profitability depends on the ability of our utility subsidiaries to recover their costs, and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.", "prior_title": "Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.", "similarity_score": 0.887, "confidence": "high", "key_changes": [ "Reworded sentence: \"Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities.\"", "Reworded sentence: \"Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations.\"", "Reworded sentence: \"Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.\"", "Reworded sentence: \"Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense.\"", "Reworded sentence: \"Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations.\"" ], "current_body": "We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could negatively impact our results of operations, financial condition or cash flows.", "prior_body": "We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery. 18 18 18 Table of Contents Table of Contents Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flow and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates. Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California Independent System Operator), in which any credit losses are socialized to all market participants. We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.Increasing costs associated with health care plans may adversely affect our results of operations.Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.We must rely on cash from our subsidiaries to make dividend payments.Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock.Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.Our credit ratings are subject to change and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.We are subject to capital market and interest rate risks.Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.We are subject to credit risks.Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flow and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates. Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. Higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Adverse regulatory rulings (including changes in recovery mechanisms) or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock." }, { "status": "MODIFIED", "current_title": "Off-Balance Sheet Arrangements", "prior_title": "Off-Balance Sheet Arrangements", "similarity_score": 0.886, "confidence": "high", "key_changes": [ "Reworded sentence: \"In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%.\"", "Reworded sentence: \"31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253) Projected pension obligation (a) (a)Excludes non-qualified plan of $13 million and $12 million at Dec.\"", "Reworded sentence: \"Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements — As of Feb.\"", "Reworded sentence: \"Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock.\"", "Reworded sentence: \"Debt issuance at our utility subsidiaries are subject to commission approval.Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings.\"" ], "current_body": "Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%. Xcel Energy’s dividend policy balances the following: •Projected cash generation. •Projected capital investment. •A reasonable rate of return on shareholder investment. •The impact on Xcel Energy’s capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See Note 5 to the consolidated financial statements for further information. Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions: (Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253) Projected pension obligation (a) (a)Excludes non-qualified plan of $13 million and $12 million at Dec. 31, 2024 and 2023, respectively. Pension Assumptions20242023Discount rate5.88 %5.49 %Expected long-term rate of return7.13 6.93 Capital SourcesShort-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements — As of Feb. 24, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $660 $840 $25 $865 PSCo700 101 599 10 609 NSP-Minnesota700 375 325 7 332 SPS500 255 245 7 252 NSP-Wisconsin150 27 123 3 126 Total$3,550 $1,418 $2,132 $52 $2,184 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.", "prior_body": "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, 2023Dec. 31, 2022Fair value of pension assets$2,690 $2,685 Projected pension obligation (a)2,943 2,871 Funded status$(253)$(186) Projected pension obligation (a) (a)Excludes non-qualified plan of $12 million and $11 million at Dec. 31, 2023 and 2022, respectively. Pension Assumptions20232022Discount rate5.49 %5.80 %Expected long-term rate of return6.93 6.93 Capital SourcesShort-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements — 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)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 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. Pension Assumptions20232022Discount rate5.49 %5.80 %Expected long-term rate of return6.93 6.93" }, { "status": "MODIFIED", "current_title": "Recovery Mechanisms", "prior_title": "Recovery Mechanisms", "similarity_score": 0.876, "confidence": "high", "key_changes": [ "Reworded sentence: \"MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs.\"" ], "current_body": "MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization.", "prior_body": "MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization." }, { "status": "MODIFIED", "current_title": "Nuclear Decommissioning", "prior_title": "Nuclear Decommissioning", "similarity_score": 0.871, "confidence": "high", "key_changes": [ "Reworded sentence: \"37 37 37 Table of Contents Table of Contents A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities.\"", "Reworded sentence: \"Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability.\"", "Reworded sentence: \"In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed.\"", "Reworded sentence: \"NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors.Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate.\"", "Reworded sentence: \"31, 2024.See Note 12 to the consolidated financial statements for further information.Loss Contingencies – WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty.\"" ], "current_body": "Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. 37 37 37 Table of Contents Table of Contents A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.5 billion in 2024 and $2.1 billion in 2023. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed. The following assumptions have a significant effect on the estimated nuclear obligation:Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively). In December 2024, the operating license for Xcel Energy’s Monticello Nuclear Generating Plant in Monticello, MN was renewed. The approval allows the plant to operate an additional 20 years, through 2050. As of Dec. 31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040. In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received.The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors.Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2024.See Note 12 to the consolidated financial statements for further information.Loss Contingencies – WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 12 accompanying the consolidated financial statements for additional information. Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.5 billion in 2024 and $2.1 billion in 2023. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed. The following assumptions have a significant effect on the estimated nuclear obligation:Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively). In December 2024, the operating license for Xcel Energy’s Monticello Nuclear Generating Plant in Monticello, MN was renewed. The approval allows the plant to operate an additional 20 years, through 2050. As of Dec. 31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040. In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received.The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors.Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.5 billion in 2024 and $2.1 billion in 2023. NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed. The following assumptions have a significant effect on the estimated nuclear obligation: Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit’s operating license with the NRC (i.e., 2050 for Monticello and 2033 and 2034 for Prairie Island Units 1 and 2, respectively). In December 2024, the operating license for Xcel Energy’s Monticello Nuclear Generating Plant in Monticello, MN was renewed. The approval allows the plant to operate an additional 20 years, through 2050. As of Dec. 31, 2024, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2033, 2034 and 2040. In February 2025, the MPUC approved the planned life extension through 2050 as part of the Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates in 2025 once additional approvals have been received. The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101. Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly. Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.8% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors. Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2024.See Note 12 to the consolidated financial statements for further information.Loss Contingencies – WildfiresThe outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 12 accompanying the consolidated financial statements for additional information. Derivatives, Risk Management and Market RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time. Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially. However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates. NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2024. See Note 12 to the consolidated financial statements for further information.", "prior_body": "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. 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 38 38 Table of Contents 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 FireThe 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 RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2023:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-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 Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$— $— $9 $8 $17 PSCo (b)4 — — — 4 $4 $— $9 $8 $21 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20232022Fair value of commodity trading net contracts outstanding at Jan. 1$(10)$(33)Contracts realized or settled during the period(2)(15)Commodity trading contract additions and changes during the period13 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 $8 million at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances.Xcel Energy’s’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2023$— $— $1 $— 20222 1 5 — 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 FireThe 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 RiskWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. 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." }, { "status": "MODIFIED", "current_title": "We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.", "prior_title": "We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.", "similarity_score": 0.864, "confidence": "high", "key_changes": [ "Reworded sentence: \"Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions.\"", "Removed sentence: \"21 21 21 Table of Contents Table of Contents We may be subject to climate change lawsuits.\"", "Removed sentence: \"An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages.\"", "Removed sentence: \"Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.\"", "Removed sentence: \"Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.\"" ], "current_body": "Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.", "prior_body": "Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency’s Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. 21 21 21 Table of Contents Table of Contents We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.We establish strategies and expectations related to climate change and other environmental matters. Our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, evolving legal, regulatory, and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, or increased costs of insurance, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets. While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. ITEM 1B — UNRESOLVED STAFF COMMENTSNone. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.We are subject to environmental laws and regulations, with which compliance could be difficult and costly.We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination. Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows." }, { "status": "MODIFIED", "current_title": "Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2024Common Stock Outstanding (Shares) as of Dec. 31, 20231,000,000,000 $2.50 574,365,598 554,941,703", "prior_title": "Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2023Common Stock Outstanding (Shares) as of Dec. 31, 20221,000,000,000 $2.50 554,941,703 549,578,018", "similarity_score": 0.862, "confidence": "high", "key_changes": [ "Reworded sentence: \"31, 2024: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2024NSP-Minnesota47.6 %58.2 %53.0 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.4 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.\"", "Reworded sentence: \"(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,809 $17,490 $17,800 NSP-Wisconsin12 2,922 N/ASPS (a)592 7,789 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating.\"", "Reworded sentence: \"31, 2024: (Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota (a)52.4% of total capitalization$2,670 NSP-Wisconsin$225 150 PSCo1,300 1,200 SPS150 700 NSP-Minnesota (a) (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.\"", "Added sentence: \"31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 — 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 — — 645 Transmission648 — — 648 Other64 175 — 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec.\"", "Reworded sentence: \"31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 — 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 — — 1,354 Transmission675 — — 675 Other97 178 — 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310\"" ], "current_body": "Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2024: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2024NSP-Minnesota47.6 %58.2 %53.0 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.4 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. (b) Excludes short-term debt. Excludes short-term debt. (Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,809 $17,490 $17,800 NSP-Wisconsin12 2,922 N/ASPS (a)592 7,789 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating. (a) Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2024: (Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota (a)52.4% of total capitalization$2,670 NSP-Wisconsin$225 150 PSCo1,300 1,200 SPS150 700 NSP-Minnesota (a) (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. 6. RevenuesRevenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 — 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 — — 645 Transmission648 — — 648 Other64 175 — 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 — 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 — — 815 Transmission649 — — 649 Other63 156 — 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 — 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 — — 1,354 Transmission675 — — 675 Other97 178 — 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310", "prior_body": "Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2023: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2023NSP-Minnesota47.2 %57.6 %52.3 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.6 NSP-Wisconsin (a) SPS (b) (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. (b) Excludes short-term debt. Excludes short-term debt. (Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,508 $15,702 $16,140 NSP-Wisconsin9 2,520 N/ASPS (a)617 7,298 N/A SPS (a) (a)May not pay a dividend that would cause a loss of its investment grade bond rating. (a) Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2023:(Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota52.8% of total capitalization(a)$2,400 (a)NSP-Wisconsin$625 150 PSCo450 800 SPS100 600 (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. 6. RevenuesRevenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 — 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 — — 815 Transmission649 — — 649 Other63 156 — 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 — 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 — — 1,354 Transmission675 — — 675 Other97 178 — 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 Amounts authorized to issue as of Dec. 31, 2023: (Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota52.8% of total capitalization(a)$2,400 (a)NSP-Wisconsin$625 150 PSCo450 800 SPS100 600 (a) (a) (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization." }, { "status": "MODIFIED", "current_title": "Derivatives, Risk Management and Market Risk", "prior_title": "Derivatives, Risk Management and Market Risk", "similarity_score": 0.861, "confidence": "high", "key_changes": [ "Added sentence: \"38 38 38 Table of Contents Table of Contents Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.\"", "Added sentence: \"Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations.\"", "Added sentence: \"Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.\"", "Added sentence: \"Commodity price risk is also managed through the use of financial derivative instruments.\"", "Added sentence: \"Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives.\"" ], "current_body": "We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk. 38 38 38 Table of Contents Table of Contents Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2024:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(16)$(19)$(4)$— $(39)NSP-Minnesota (b)3 10 (4)2 11 PSCo (a)1 5 — — 6 $(12)$(4)$(8)$2 $(22)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$— $— $20 $— $20 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20242023Fair value of commodity trading net contracts outstanding at Jan. 1$1 $(10)Contracts realized or settled during the period— (2)Commodity trading contract additions and changes during the period(3)13 Fair value of commodity trading net contracts outstanding at Dec. 31$(2)$1 A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2024 and $4 million at Dec. 31, 2023.The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2024$— $— $1 $— 2023— — 1 — Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2024:Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(16)$(19)$(4)$— $(39)NSP-Minnesota (b)3 10 (4)2 11 PSCo (a)1 5 — — 6 $(12)$(4)$(8)$2 $(22)Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$— $— $20 $— $20 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20242023Fair value of commodity trading net contracts outstanding at Jan. 1$1 $(10)Contracts realized or settled during the period— (2)Commodity trading contract additions and changes during the period(3)13 Fair value of commodity trading net contracts outstanding at Dec. 31$(2)$1 A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2024 and $4 million at Dec. 31, 2023.The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions. Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund. Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee. Fair value of net commodity trading contracts as of Dec. 31, 2024: Futures / Forwards Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (a)$(16)$(19)$(4)$— $(39)NSP-Minnesota (b)3 10 (4)2 11 PSCo (a)1 5 — — 6 $(12)$(4)$(8)$2 $(22) NSP-Minnesota (a) NSP-Minnesota (b) PSCo (a)", "prior_body": "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 Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-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 Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$— $— $9 $8 $17 PSCo (b)4 — — — 4 $4 $— $9 $8 $21 (a)Prices actively quoted or based on actively quoted prices.(b)Prices based on models and other valuation methods.Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:(Millions of Dollars)20232022Fair value of commodity trading net contracts outstanding at Jan. 1$(10)$(33)Contracts realized or settled during the period(2)(15)Commodity trading contract additions and changes during the period13 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 $8 million at Dec. 31, 2022. Market price movements can exceed 10% under abnormal circumstances.Xcel Energy’s’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:(Millions of Dollars)Year Ended Dec. 31AverageHighLow2023$— $— $1 $— 20222 1 5 — 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 Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-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) NSP-Minnesota (a) NSP-Minnesota (b) PSCo (a) PSCo (b) Options Maturity(Millions of Dollars)Less Than1 Year1 to 3 Years4 to 5 YearsGreater Than5 YearsTotal Fair ValueNSP-Minnesota (b)$— $— $9 $8 $17 PSCo (b)4 — — — 4 $4 $— $9 $8 $21 NSP-Minnesota (b) PSCo (b) (a)Prices actively quoted or based on actively quoted prices. (b)Prices based on models and other valuation methods. Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31: (Millions of Dollars)20232022Fair value of commodity trading net contracts outstanding at Jan. 1$(10)$(33)Contracts realized or settled during the period(2)(15)Commodity trading contract additions and changes during the period13 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:" }, { "status": "MODIFIED", "current_title": "Recovery Mechanisms", "prior_title": "Recovery Mechanisms", "similarity_score": 0.859, "confidence": "high", "key_changes": [ "Reworded sentence: \"MechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill.DSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel and purchased energy costs.\"", "Reworded sentence: \"PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC.\"", "Reworded sentence: \"The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.\"" ], "current_body": "MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization.", "prior_body": "MechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization." }, { "status": "MODIFIED", "current_title": "Employee Benefits", "prior_title": "Employee Benefits", "similarity_score": 0.85, "confidence": "high", "key_changes": [ "Reworded sentence: \"36 36 36 Table of Contents Table of Contents At Dec.\"", "Reworded sentence: \"This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec.\"", "Reworded sentence: \"In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation:Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits.\"", "Reworded sentence: \"31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%.\"", "Reworded sentence: \"Funding contributions in 2024 were $100 million and will be $125 million in 2025.\"" ], "current_body": "We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. 36 36 36 Table of Contents Table of Contents At Dec. 31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set at Dec. 31, 2023. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2024, which is a 125 basis point increase from the rate set in 2023. Xcel Energy’s pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan’s funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec. 31, 2024. This represents a 39 basis point and 34 basis point increase, respectively, from 2023. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation:Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.As of Dec. 31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan. Funding contributions in 2024 were $100 million and will be $125 million in 2025. In future years contributions will decrease slightly but then remain relatively consistent. Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023.The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2024).Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023. The expected decrease in 2025 is primarily due to the absence of a pension settlement.Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2022 - 2025:•$125 million in January 2025.•$100 million in 2024.•$50 million in 2023.•$50 million in 2022.Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2025. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2024.See Note 11 to the consolidated financial statements for further information.Nuclear DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. At Dec. 31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set at Dec. 31, 2023. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2024, which is a 125 basis point increase from the rate set in 2023. Xcel Energy’s pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan’s funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec. 31, 2024. This represents a 39 basis point and 34 basis point increase, respectively, from 2023. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation:Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.As of Dec. 31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan. Funding contributions in 2024 were $100 million and will be $125 million in 2025. In future years contributions will decrease slightly but then remain relatively consistent. Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023.The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. At Dec. 31, 2024, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which is a 20 basis point increase from the rate set at Dec. 31, 2023. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2024, which is a 125 basis point increase from the rate set in 2023. Xcel Energy’s pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan’s funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios. Xcel Energy set the discount rates used to value both the pension obligations and postretirement health care obligations at 5.88% at Dec. 31, 2024. This represents a 39 basis point and 34 basis point increase, respectively, from 2023. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected. If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2025 pension costs, net of the effects of regulation: Pension Costs(Millions of Dollars)+1%-1%Rate of return $(12)$24 Discount rate (2)2 Discount rate Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate. As of Dec. 31, 2024, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan. Funding contributions in 2024 were $100 million and will be $125 million in 2025. In future years contributions will decrease slightly but then remain relatively consistent. Investment returns were less than the assumed levels in 2024 and 2022, but were more than the assumed levels in 2023. The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2024).Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023. The expected decrease in 2025 is primarily due to the absence of a pension settlement.Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2022 - 2025:•$125 million in January 2025.•$100 million in 2024.•$50 million in 2023.•$50 million in 2022.Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2025. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2024.See Note 11 to the consolidated financial statements for further information.Nuclear DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2024). Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $60 million in 2025 and $69 million in 2026, while the actual pension costs were $79 million in 2024 and $74 in 2023. The expected decrease in 2025 is primarily due to the absence of a pension settlement. Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2022 - 2025: •$125 million in January 2025. •$100 million in 2024. •$50 million in 2023. •$50 million in 2022. Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $11 million and $13 million during 2024, 2023 and 2022, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2025. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below. •NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability. •PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset. •Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions. •PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2024. See Note 11 to the consolidated financial statements for further information.", "prior_body": "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.•$131 million in 2021. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected. If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2023 pension costs: Pension Costs(Millions of Dollars)+1%-1%Rate of return (a)$(10)$26 Discount rate (a)3 8 Rate of return (a) Discount rate (a) (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 37 37 Table of Contents 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 DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory 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. 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 DecommissioningXcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning were $2.1 billion in 2023 and $2.2 billion in 2022. Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $11 million, $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." }, { "status": "MODIFIED", "current_title": "CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY", "prior_title": "CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY", "similarity_score": 0.847, "confidence": "high", "key_changes": [ "Reworded sentence: \"31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 Net income1,736 1,736 Other comprehensive income30 30 Dividends declared on common stock ($1.95 per share)(1,066)(1,066)Issuances of common stock5,552,749 14 345 359 Share-based compensation7 (3)4 Balance at Dec.\"" ], "current_body": "(amounts in millions, except per share data; shares in actual amounts) Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholders’ EquitySharesPar ValueAdditional PaidIn CapitalBalance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 Net income1,736 1,736 Other comprehensive income30 30 Dividends declared on common stock ($1.95 per share)(1,066)(1,066)Issuances of common stock5,552,749 14 345 359 Share-based compensation7 (3)4 Balance at Dec. 31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 Net Income1,771 1,771 Other comprehensive loss(1)(1)Dividends declared on common stock ($2.08 per share)(1,148)(1,148)Issuances of common stock5,363,685 13 295 308 Share-based compensation15 (4)11 Balance at Dec. 31, 2023554,941,703 $1,387 $8,465 $7,858 $(94)$17,616 Net income1,936 1,936 Other comprehensive income26 26 Dividends declared on common stock ($2.19 per share)(1,236)(1,236)Issuances of common stock19,423,895 49 1,098 1,147 Share-based compensation38 (5)33 Balance at Dec. 31, 2024574,365,598 $1,436 $9,601 $8,553 $(68)$19,522 See Notes to Consolidated Financial Statements", "prior_body": "(amounts in millions, except per share data; shares in actual amounts) Common Stock IssuedRetained EarningsAccumulated Other Comprehensive LossTotal Common Stockholders’ EquitySharesPar ValueAdditional PaidIn CapitalBalance at Dec. 31, 2020537,438,394 $1,344 $7,404 $5,968 $(141)$14,575 Net income1,597 1,597 Other comprehensive income18 18 Dividends declared on common stock ($1.83 per share)(989)(989)Issuances of common stock6,586,875 16 387 403 Share-based compensation12 (4)8 Balance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 Net Income1,736 1,736 Other comprehensive loss30 30 Dividends declared on common stock ($1.95 per share)(1,066)(1,066)Issuances of common stock5,552,749 14 345 359 Share-based compensation7 (3)4 Balance at Dec. 31, 2022549,578,018 $1,374 $8,155 $7,239 $(93)$16,675 Net income1,771 1,771 Other comprehensive income(1)(1)Dividends declared on common stock ($2.08 per share)(1,148)(1,148)Issuances of common stock5,363,685 13 295 308 Share-based compensation15 (4)11 Balance at Dec. 31, 2023554,941,703 $1,387 $8,465 $7,858 $(94)$17,616 See Notes to Consolidated Financial Statements" }, { "status": "MODIFIED", "current_title": "Purchased Power and Transmission Service Providers", "prior_title": "Purchased Power and Transmission Service Providers", "similarity_score": 0.843, "confidence": "high", "key_changes": [ "Removed sentence: \"Energy Markets — PSCo joined the SPP Western Energy Imbalance Service Market in April 2023.\"", "Removed sentence: \"This market is an incremental step in the participation in an organized wholesale market.\"", "Removed sentence: \"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.\"", "Removed sentence: \"The result improves balancing supply and demand at a lower cost.\"" ], "current_body": "PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs. Purchased Power — PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo’s long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost. Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.", "prior_body": "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." }, { "status": "MODIFIED", "current_title": "Station, Location and Unit at Dec. 31, 2024", "prior_title": "Station, Location and Unit at Dec. 31, 2023", "similarity_score": 0.839, "confidence": "high", "key_changes": [ "Reworded sentence: \"MW (a) (b) (c) Hayden-Hayden, CO, 2 Units (d) (e) (e) (a)Summer 2024 net dependable capacity.\"", "Reworded sentence: \"31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%.\"", "Reworded sentence: \"31, 2024 SPS’ wind facilities had a weighted-average capacity factor of 50%.\"", "Reworded sentence: \"The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 38 companies at year-end and is a broad measure of industry performance.Comparison of Five Year Cumulative Total Return** $100 invested on Dec.\"", "Reworded sentence: \"31, 2024FuelInstalledMW (a)Steam:Cunningham-Hobbs, NM, 1 UnitNatural Gas1957 - 1965183 Harrington-Amarillo, TX 1 UnitNatural Gas2024339 (b)Harrington-Amarillo, TX 2 UnitsCoal1976 - 1980679 (b)Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 Plant X-Earth, TX, 1 UnitNatural Gas1952 - 1964190 Tolk-Muleshoe, TX, 2 UnitsCoal1982 - 19851,067 Combustion Turbine:Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 Wind:Hale-Plainview, TX, 239 UnitsWind2019478 (c)Sagamore-Dora, NM, 240 UnitsWind2020507 (c)Total5,100 (a)Summer 2024 net dependable capacity.\"" ], "current_body": "MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota’s ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500", "prior_body": "MW (a) (b) (c) (d) (e) (e) (e) (e) (e) (e) (e) (e) (e) Grand Meadow-Mower County, MN, 67 Units (f) (e) (e) (e) (e) (e) Northern Wind-Murray County, MN, 37 Units (g) (e) (e) (e) (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity. (b)Retired on Dec. 31, 2023. (c)Based on NSP-Minnesota’s ownership of 59%. (d)RDF is made from municipal solid waste. (e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, NSP-Minnesota’s wind facilities had a weighted-average capacity factors of 43%. (f)Repowered in 2023. (g)Purchased in 2023. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551 (a)Summer 2023 net dependable capacity.(b)RDF is made from municipal solid waste.PSCoStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Various locations, 8 UnitsNatural GasVarious247 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2023, PSCo’s wind facilities had a weighted-average capacity factors of 43%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2023FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973240 Hydro:Various locations, 62 UnitsHydroVarious135 Total551" }, { "status": "MODIFIED", "current_title": "Other Utility Items", "prior_title": "Other Utility Items", "similarity_score": 0.838, "confidence": "high", "key_changes": [ "Added sentence: \"An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis.\"", "Added sentence: \"The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2.\"", "Added sentence: \"Accounting PronouncementsRecently AdoptedSegment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker.\"", "Added sentence: \"Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec.\"", "Added sentence: \"The adoption impacts were not material.See Note 14 for further information.\"" ], "current_body": "AFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base. AFUDC — Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsRecently AdoptedSegment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material.See Note 14 for further information. Recently IssuedIncome Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements. Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements.Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disaggregated disclosure of income statement expenses for public business entities. The ASU is effective for annual periods beginning after Dec. 15, 2026. Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.", "prior_body": "AFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base. AFUDC — Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsRecently IssuedSegment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Property, plant and equipment, netElectric plant$52,494 $49,639 Natural gas plant9,080 8,514 Common and other property3,190 2,970 Plant to be retired (a)2,055 2,217 CWIP2,873 2,124 Total property, plant and equipment69,692 65,464 Less accumulated depreciation(18,399)(17,502)Nuclear fuel3,337 3,183 Less accumulated amortization(2,988)(2,892)Property, plant and equipment, net$51,642 $48,253 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net of accumulated depreciation. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income." }, { "status": "MODIFIED", "current_title": "Additional Information", "prior_title": "Additional Information", "similarity_score": 0.836, "confidence": "high", "key_changes": [ "Reworded sentence: \"Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs.\"" ], "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025.", "prior_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers 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 Proceedings2022 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" }, { "status": "MODIFIED", "current_title": "Wholesale and Commodity Marketing Operations", "prior_title": "Wholesale and Commodity Marketing Operations", "similarity_score": 0.833, "confidence": "high", "key_changes": [ "Added sentence: \"33 33 33 Table of Contents Table of Contents SPSSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPUCTRetail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations.The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities.\"", "Added sentence: \"The municipalities’ rate setting decisions are subject to PUCT review.\"", "Added sentence: \"NMPRCRetail electric operations, retail rates and services and the construction of transmission or generation.Reviews Integrated Resource Plans for meeting future energy needs.FERCWholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.SPP RTO and SPP Integrated and Wholesale MarketsSPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets.\"", "Added sentence: \"SPS is authorized to make wholesale electric sales at market-based prices.\"", "Added sentence: \"DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAdvanced Metering System SurchargeRecovers costs incurred in deployment of the Advanced Metering System in Texas.Consulting Fee RiderRecovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT.Distribution Cost Recovery FactorRecovers distribution costs not included in rates in Texas.Electric Vehicle RiderRecovers costs of the Transportation Electrification Plan in New Mexico.Energy Efficiency Cost Recovery FactorRecovers costs for energy efficiency programs in Texas.Energy Efficiency RiderRecovers costs for energy efficiency programs in New Mexico.Fixed Fuel and Purchased Recovery FactorProvides for the over- or under-recovery of energy expenses in Texas.\"" ], "current_body": "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", "prior_body": "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" }, { "status": "MODIFIED", "current_title": "CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME", "prior_title": "CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME", "similarity_score": 0.832, "confidence": "high", "key_changes": [ "Reworded sentence: \"31202420232022Net income$1,936 $1,771 $1,736 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical (losses) gains arising during the period, net of tax (3)(4)5 Reclassification of losses to net income, net of tax 5 2 4 Derivative instruments:Net fair value increase (decrease), net of tax22 (2)16 Reclassification of losses to net income, net of tax 2 3 5 Total other comprehensive income (loss)26 (1)30 Total comprehensive income$1,962 $1,770 $1,766 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents\"" ], "current_body": "(amounts in millions) Year Ended Dec. 31202420232022Net income$1,936 $1,771 $1,736 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical (losses) gains arising during the period, net of tax (3)(4)5 Reclassification of losses to net income, net of tax 5 2 4 Derivative instruments:Net fair value increase (decrease), net of tax22 (2)16 Reclassification of losses to net income, net of tax 2 3 5 Total other comprehensive income (loss)26 (1)30 Total comprehensive income$1,962 $1,770 $1,766 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents", "prior_body": "(amounts in millions) Year Ended Dec. 31202320222021Net income$1,771 $1,736 $1,597 Other comprehensive incomePension and retiree medical benefits:Net pension and retiree medical (losses) gains arising during the period, net of tax (4)5 — Reclassification of losses to net income, net of tax 2 4 8 Derivative instruments:Net fair value (decrease) increase, net of tax(2)16 4 Reclassification of losses to net income, net of tax 3 5 6 Total other comprehensive (loss) income(1)30 18 Total comprehensive income$1,770 $1,766 $1,615 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "Material Cash Requirements and Other Commitments", "prior_title": "Material Cash Requirements and Other Commitments", "similarity_score": 0.829, "confidence": "high", "key_changes": [ "Reworded sentence: \"31, 2024)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$50,915 $2,292 $3,316 $3,846 $41,461 Finance lease obligations208 10 17 16 165 Operating leases obligations (a)1,355 271 432 215 437 Unconditional purchase obligations (b) (c)3,755 1,432 1,207 432 684 Other long-term obligations, including current portion (d)85 20 36 29 — Other short-term obligations632 632 — — — Short-term debt695 695 — — — Total contractual cash obligations$57,645 $5,352 $5,008 $4,538 $42,747 Operating leases obligations (a) Unconditional purchase obligations (b) (c) Other long-term obligations, including current portion (d) (a)Included in operating lease obligations are $240 million, $372 million, $166 million and $199 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases.\"", "Reworded sentence: \"(c)Amounts exclude approximately $1 billion of incremental payments related to SPS’ renegotiation and extension of a non-lease PPA that received PUCT approval in February 2025.\"", "Reworded sentence: \"Capital Expenditures — Base capital expenditures for Xcel Energy for 2025 through 2029: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2024202520262027202820292025 - 2029 TotalPSCo$3,180 $5,820 $5,190 $3,940 $3,780 $3,550 $22,280 NSP-Minnesota2,830 3,240 2,500 2,830 2,080 2,570 13,220 SPS1,100 1,400 1,540 1,280 1,040 1,040 6,300 NSP-Wisconsin560 640 650 690 660 670 3,310 Other (a)(20)(100)(40)10 10 10 (110)Total base capital expenditures$7,650 $11,000 $9,840 $8,750 $7,570 $7,840 $45,000 Other (a) (a)Other category includes intercompany transfers for safe harbor wind turbines.\"", "Reworded sentence: \"Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.Financing for Capital Expenditures through 2029 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes.\"", "Reworded sentence: \"Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.\"" ], "current_body": "Payments Due by Period (as of Dec. 31, 2024)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$50,915 $2,292 $3,316 $3,846 $41,461 Finance lease obligations208 10 17 16 165 Operating leases obligations (a)1,355 271 432 215 437 Unconditional purchase obligations (b) (c)3,755 1,432 1,207 432 684 Other long-term obligations, including current portion (d)85 20 36 29 — Other short-term obligations632 632 — — — Short-term debt695 695 — — — Total contractual cash obligations$57,645 $5,352 $5,008 $4,538 $42,747 Operating leases obligations (a) Unconditional purchase obligations (b) (c) Other long-term obligations, including current portion (d) (a)Included in operating lease obligations are $240 million, $372 million, $166 million and $199 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases. (b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms. (c)Amounts exclude approximately $1 billion of incremental payments related to SPS’ renegotiation and extension of a non-lease PPA that received PUCT approval in February 2025. The extension to 2040 will result in annual payments of approximately $65 million to $80 million commencing in 2025. (d)Primarily consists of contracts for information technology services. Capital Expenditures — Base capital expenditures for Xcel Energy for 2025 through 2029: Actual Base Capital Forecast (Millions of Dollars)By Regulated Utility2024202520262027202820292025 - 2029 TotalPSCo$3,180 $5,820 $5,190 $3,940 $3,780 $3,550 $22,280 NSP-Minnesota2,830 3,240 2,500 2,830 2,080 2,570 13,220 SPS1,100 1,400 1,540 1,280 1,040 1,040 6,300 NSP-Wisconsin560 640 650 690 660 670 3,310 Other (a)(20)(100)(40)10 10 10 (110)Total base capital expenditures$7,650 $11,000 $9,840 $8,750 $7,570 $7,840 $45,000 Other (a) (a)Other category includes intercompany transfers for safe harbor wind turbines. ActualBase Capital Forecast (Millions of Dollars)By Function2024202520262027202820292025 - 2029 TotalElectric distribution$2,220 $2,570 $3,000 $3,400 $3,320 $3,540 $15,830 Electric transmission1,720 2,260 2,860 2,740 2,390 2,310 12,560 Renewables1,130 3,360 1,400 260 — — 5,020 Electric generation960 1,210 1,150 910 580 620 4,470 Natural gas780 800 680 690 630 620 3,420 Other840 800 750 750 650 750 3,700 Total base capital expenditures$7,650 $11,000 $9,840 $8,750 $7,570 $7,840 $45,000 The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.Financing for Capital Expenditures through 2029 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through an RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt. Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities. Financing for Capital Expenditures through 2029 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Financing for Capital Expenditures through 2029 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. 41 41 41 Table of Contents Table of Contents Current estimated financing plans of Xcel Energy for 2025 through 2029 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$25,320 New debt (b)15,180 Equity through the DRIP and benefit program500 Other equity4,000 Base capital expenditures 2025 - 2029$45,000 Maturing debt$3,730 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%.Xcel Energy’s dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy’s capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253)(a)Excludes non-qualified plan of $13 million and $12 million at Dec. 31, 2024 and 2023, respectively.Pension Assumptions20242023Discount rate5.88 %5.49 %Expected long-term rate of return7.13 6.93 Capital SourcesShort-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements — As of Feb. 24, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:(Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $660 $840 $25 $865 PSCo700 101 599 10 609 NSP-Minnesota700 375 325 7 332 SPS500 255 245 7 252 NSP-Wisconsin150 27 123 3 126 Total$3,550 $1,418 $2,132 $52 $2,184 (a)Credit facilities expire in September 2027.(b)Includes outstanding commercial paper and letters of credit.Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. Current estimated financing plans of Xcel Energy for 2025 through 2029 (includes the impact of tax credit transferability):(Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$25,320 New debt (b)15,180 Equity through the DRIP and benefit program500 Other equity4,000 Base capital expenditures 2025 - 2029$45,000 Maturing debt$3,730 (a)Net of dividends and pension funding.(b)Reflects a combination of short and long-term debt; net of refinancing.Off-Balance Sheet ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2025, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.1%.Xcel Energy’s dividend policy balances the following:•Projected cash generation.•Projected capital investment.•A reasonable rate of return on shareholder investment.•The impact on Xcel Energy’s capital structure and credit ratings.In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.See Note 5 to the consolidated financial statements for further information.Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds. Funded status and pension assumptions:(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Fair value of pension assets$2,504 $2,690 Projected pension obligation (a)2,752 2,943 Funded status$(248)$(253)(a)Excludes non-qualified plan of $13 million and $12 million at Dec. 31, 2024 and 2023, respectively.Pension Assumptions20242023Discount rate5.88 %5.49 %Expected long-term rate of return7.13 6.93 Current estimated financing plans of Xcel Energy for 2025 through 2029 (includes the impact of tax credit transferability): (Millions of Dollars)Funding Capital ExpendituresCash from operations (a)$25,320 New debt (b)15,180 Equity through the DRIP and benefit program500 Other equity4,000 Base capital expenditures 2025 - 2029$45,000 Maturing debt$3,730 Cash from operations (a) New debt (b) (a)Net of dividends and pension funding. (b)Reflects a combination of short and long-term debt; net of refinancing.", "prior_body": "Payments Due by Period (as of Dec. 31, 2023)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 YearsLong-term debt, principal and interest payments$43,659 $1,567 $3,631 $3,564 $34,897 Finance lease obligations218 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 obligations591 591 — — — Short-term debt785 785 — — — Total contractual cash obligations$50,852 $4,677 $5,453 $4,591 $36,131 Operating leases obligations (a) Unconditional purchase obligations (b) (c) Other long-term obligations, including current portion (d) (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 Utility2023202420252026202720282024 - 2028 TotalPSCo$2,310 $3,300 $5,230 $4,320 $3,620 $2,730 $19,200 NSP-Minnesota2,370 2,660 2,970 2,380 2,500 2,540 13,050 SPS750 910 780 660 870 830 4,050 NSP-Wisconsin450 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 Other (a) (a)Other category includes intercompany transfers for safe harbor wind turbines. ActualBase Capital Forecast (Millions of Dollars)By Function2023202420252026202720282024 - 2028 TotalElectric transmission$1,320 $1,710 $2,020 $2,450 $2,850 $2,470 $11,500 Electric distribution1,730 1,770 1,960 2,200 2,200 2,470 10,600 Renewables350 1,500 2,910 940 240 20 5,610 Electric generation780 940 1,290 1,050 1,060 600 4,940 Natural gas780 740 680 630 620 570 3,240 Other1,250 760 420 670 630 630 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. 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. 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. 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 41 41 Table of Contents 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 ExpendituresCash from operations (a)$22,000 New debt (b)13,000 Equity through the DRIP and benefit program500 Other equity3,500 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 ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 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, 2023Dec. 31, 2022Fair 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 Assumptions20232022Discount rate5.49 %5.80 %Expected long-term rate of return6.93 6.93 Capital SourcesShort-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:•$1.50 billion for Xcel Energy Inc.•$700 million for PSCo.•$700 million for NSP-Minnesota.•$500 million for SPS.•$150 million for NSP-Wisconsin.See Note 5 to the consolidated financial statements for further information.Credit Facility Agreements — 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)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 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. 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 ExpendituresCash from operations (a)$22,000 New debt (b)13,000 Equity through the DRIP and benefit program500 Other equity3,500 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 ArrangementsXcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 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, 2023Dec. 31, 2022Fair 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. 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 ExpendituresCash from operations (a)$22,000 New debt (b)13,000 Equity through the DRIP and benefit program500 Other equity3,500 Base capital expenditures 2024 - 2028$39,000 Maturing Debt$3,780 Cash from operations (a) New debt (b) (a)Net of dividends and pension funding. (b)Reflects a combination of short and long-term debt; net of refinancing." }, { "status": "MODIFIED", "current_title": "Statement of Income Analysis", "prior_title": "Statement of Income Analysis", "similarity_score": 0.828, "confidence": "high", "key_changes": [ "Reworded sentence: \"However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.\"", "Reworded sentence: \"Percentage increase (decrease) in normal and actual HDD, CDD and THI:2024 vs.Normal2023 vs.Normal2024 vs.\"", "Reworded sentence: \"Percentage increase (decrease) in normal and actual HDD, CDD and THI:2024 vs.Normal2023 vs.Normal2024 vs.\"", "Reworded sentence: \"Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2024 vs.Normal2023 vs.Normal2024 vs.\"" ], "current_body": "The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income. Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. 26 26 26 Table of Contents Table of Contents HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2024 vs.Normal2023 vs.Normal2024 vs. 2023HDD(15.4)%(7.3)%(9.8)%CDD28.1 5.2 23 THI(11.2)16.0 (22.5)Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:2024 vs. Normal2023 vs. Normal2024 vs. 2023Retail electric$(0.008)$0.013 $(0.021)Decoupling and sales true-up0.047 (0.007)0.054 Electric total$0.039 $0.006 $0.033 Firm natural gas(0.070)(0.010)(0.060)Decoupling$0.027 $0.013 $0.014 Gas total$(0.043)$0.003 $(0.046)Total$(0.004)$0.009 $(0.013)Sales — Sales growth (decline) for actual and weather-normalized sales:2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(4.1)%3.9 %0.7 %(3.5)%(0.4)%Electric C&I(2.6)— 9.3 (1.9)1.7 Total retail electric sales(3.1)1.3 7.8 (2.4)1.1 Firm natural gas sales(8.0)(6.9)N/A(7.5)(7.2)2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential0.2 %0.9 %(1.2)%(1.5)%0.2 %Electric C&I(1.7)(1.1)9.3 (1.6)1.7 Total retail electric sales(1.1)(0.4)7.4 (1.5)1.3 Firm natural gas sales(1.1)0.6 N/A(2.5)(0.2)2024 vs. 2023 (Leap Year Adjusted)NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential(0.1)%0.7 %(1.5)%(1.8)%(0.1)%Electric C&I(2.0)(1.4)9.0 (1.8)1.5 Total retail electric sales(1.4)(0.7)7.1 (1.8)1.0 Firm natural gas sales(1.7)— N/A(3.1)(0.7)Annual weather-normalized and leap year adjusted electric sales growth (decline)•NSP-Minnesota — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector.•PSCo — Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining. •SPS — Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining. •NSP-Wisconsin — Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.Annual weather-normalized and leap year adjusted natural gas sales growth (decline)•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions. Electric RevenuesElectric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of electric fuel and purchase power(479)PTCs flowed back to customers (offset by lower ETR)(302)Wholesale generation revenues(96)Sherco Unit 3 2011 outage refunds(47)Regulatory rate outcomes (MN, CO, TX, and NM)372 Non-fuel riders169 Conservation and demand side management (offset in expense)102 Estimated impact of weather (net of sales true-up)24 Other, net(42)Total decrease$(299) HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI:2024 vs.Normal2023 vs.Normal2024 vs. 2023HDD(15.4)%(7.3)%(9.8)%CDD28.1 5.2 23 THI(11.2)16.0 (22.5)Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:2024 vs. Normal2023 vs. Normal2024 vs. 2023Retail electric$(0.008)$0.013 $(0.021)Decoupling and sales true-up0.047 (0.007)0.054 Electric total$0.039 $0.006 $0.033 Firm natural gas(0.070)(0.010)(0.060)Decoupling$0.027 $0.013 $0.014 Gas total$(0.043)$0.003 $(0.046)Total$(0.004)$0.009 $(0.013)Sales — Sales growth (decline) for actual and weather-normalized sales:2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(4.1)%3.9 %0.7 %(3.5)%(0.4)%Electric C&I(2.6)— 9.3 (1.9)1.7 Total retail electric sales(3.1)1.3 7.8 (2.4)1.1 Firm natural gas sales(8.0)(6.9)N/A(7.5)(7.2)2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential0.2 %0.9 %(1.2)%(1.5)%0.2 %Electric C&I(1.7)(1.1)9.3 (1.6)1.7 Total retail electric sales(1.1)(0.4)7.4 (1.5)1.3 Firm natural gas sales(1.1)0.6 N/A(2.5)(0.2) HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates. Percentage increase (decrease) in normal and actual HDD, CDD and THI: 2024 vs.Normal2023 vs.Normal2024 vs. 2023HDD(15.4)%(7.3)%(9.8)%CDD28.1 5.2 23 THI(11.2)16.0 (22.5) Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:2024 vs. Normal2023 vs. Normal2024 vs. 2023Retail electric$(0.008)$0.013 $(0.021)Decoupling and sales true-up0.047 (0.007)0.054 Electric total$0.039 $0.006 $0.033 Firm natural gas(0.070)(0.010)(0.060)Decoupling$0.027 $0.013 $0.014 Gas total$(0.043)$0.003 $(0.046)Total$(0.004)$0.009 $(0.013) Sales — Sales growth (decline) for actual and weather-normalized sales: 2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric residential(4.1)%3.9 %0.7 %(3.5)%(0.4)%Electric C&I(2.6)— 9.3 (1.9)1.7 Total retail electric sales(3.1)1.3 7.8 (2.4)1.1 Firm natural gas sales(8.0)(6.9)N/A(7.5)(7.2) 2024 vs. 2023NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential0.2 %0.9 %(1.2)%(1.5)%0.2 %Electric C&I(1.7)(1.1)9.3 (1.6)1.7 Total retail electric sales(1.1)(0.4)7.4 (1.5)1.3 Firm natural gas sales(1.1)0.6 N/A(2.5)(0.2)", "prior_body": "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 27 27 Table of Contents 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.Normal2022 vs.Normal2023 vs. 2022HDD(7.3)%6.5 %(12.9)%CDD5.2 23.7 (13.8)THI16.0 5.6 9 Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:2023 vs. Normal2022 vs. Normal2023 vs. 2022Retail 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. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric 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. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.0 %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 MarginElectric 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)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 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.Normal2022 vs.Normal2023 vs. 2022HDD(7.3)%6.5 %(12.9)%CDD5.2 23.7 (13.8)THI16.0 5.6 9 Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:2023 vs. Normal2022 vs. Normal2023 vs. 2022Retail 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. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric 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) 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.Normal2022 vs.Normal2023 vs. 2022HDD(7.3)%6.5 %(12.9)%CDD5.2 23.7 (13.8)THI16.0 5.6 9 Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:2023 vs. Normal2022 vs. Normal2023 vs. 2022Retail 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. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyActualElectric 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. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.0 %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 MarginElectric 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)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 2023 vs. 2022NSP-MinnesotaPSCoSPSNSP-WisconsinXcel EnergyWeather-normalized Electric residential1.0 %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" }, { "status": "MODIFIED", "current_title": "Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)", "prior_title": "Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)", "similarity_score": 0.823, "confidence": "high", "key_changes": [ "Reworded sentence: \"For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature.\"", "Reworded sentence: \"The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:(Millions of Dollars)20242023GAAP net income$1,936 $1,771 Loss on Comanche Unit 3 litigation— 35 Workforce reduction expenses— 72 Sherco Unit 3 2011 outage refunds47 — Less: tax effect of adjustments(13)(27)Ongoing earnings (a)$1,969 $1,851 (a)Amounts may not add due to rounding.Twelve Months Ended Dec.\"", "Reworded sentence: \"and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 (a)Amounts may not add due to rounding.Adjustments to GAAP net income include:Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine.\"", "Reworded sentence: \"Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023.\"", "Reworded sentence: \"and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 PSCo (a) Regulated utility (a) Total (a) (a)Amounts may not add due to rounding.\"" ], "current_body": "GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:(Millions of Dollars)20242023GAAP net income$1,936 $1,771 Loss on Comanche Unit 3 litigation— 35 Workforce reduction expenses— 72 Sherco Unit 3 2011 outage refunds47 — Less: tax effect of adjustments(13)(27)Ongoing earnings (a)$1,969 $1,851 (a)Amounts may not add due to rounding.Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo1.39 — 1.39 SPS0.70 — 0.70 NSP-Wisconsin0.24 — 0.24 Earnings from equity method investments — WYCO0.03 — 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33)— (0.33)Total (a)$3.44 0.06 $3.50 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 — 0.25 Earnings from equity method investments — WYCO0.04 — 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 (a)Amounts may not add due to rounding.Adjustments to GAAP net income include:Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage. Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs.Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs and streamline the organization for long-term success. Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program. Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings: (Millions of Dollars)20242023GAAP net income$1,936 $1,771 Loss on Comanche Unit 3 litigation— 35 Workforce reduction expenses— 72 Sherco Unit 3 2011 outage refunds47 — Less: tax effect of adjustments(13)(27)Ongoing earnings (a)$1,969 $1,851 Ongoing earnings (a) (a)Amounts may not add due to rounding. Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo1.39 — 1.39 SPS0.70 — 0.70 NSP-Wisconsin0.24 — 0.24 Earnings from equity method investments — WYCO0.03 — 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33)— (0.33)Total (a)$3.44 0.06 $3.50 Regulated utility (a) Total (a) Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 — 0.25 Earnings from equity method investments — WYCO0.04 — 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 PSCo (a) Regulated utility (a) Total (a) (a)Amounts may not add due to rounding. Adjustments to GAAP net income include: Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage. Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs. Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs and streamline the organization for long-term success. Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program. Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023. 25 25 25 Table of Contents Table of Contents Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments — WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc. and Other(0.33)(0.31)GAAP Diluted EPS (a)3.44 3.21 Loss on Comanche Unit 3 litigation— 0.05 Workforce reduction expenses— 0.09 Sherco Unit 3 2011 outage refunds0.06 — Ongoing Diluted EPS (a)$3.50 $3.35 (a)Amounts may not add due to rounding.Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2024 Comparison with 2023Xcel Energy — GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges. PSCo — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges. SPS — GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth.NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation.Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.Changes in Diluted EPSComponents significantly contributing to changes in 2024 EPS compared with 2023:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS — 2023$3.21 Components of change — 2024 vs. 2023Electric regulatory rate outcomes and riders0.73 Higher other income, net0.16 Natural gas regulatory rate outcomes and riders0.14 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Higher depreciation and amortization(0.40)Interest charges, net of AFUDC - debt(0.24)Higher O&M expenses(0.13)Sherco Unit 3 2011 outage refunds(0.06)Other, net(0.11)GAAP diluted EPS — 2024$3.44 Sherco Unit 3 2011 outage refunds0.06 Ongoing diluted EPS — 2024$3.50 ROE for Xcel Energy and its utility subsidiaries:20242023ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.07 %9.46 %8.82 %9.11 %PSCo7.63 7.63 7.32 7.77 SPS9.57 9.57 9.80 9.98 NSP-Wisconsin8.98 8.98 10.38 10.67 Utility Subsidiaries8.55 8.69 8.45 8.79 Xcel Energy10.42 10.61 10.33 10.79 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments — WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc. and Other(0.33)(0.31)GAAP Diluted EPS (a)3.44 3.21 Loss on Comanche Unit 3 litigation— 0.05 Workforce reduction expenses— 0.09 Sherco Unit 3 2011 outage refunds0.06 — Ongoing Diluted EPS (a)$3.50 $3.35 (a)Amounts may not add due to rounding.Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.2024 Comparison with 2023Xcel Energy — GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges. PSCo — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges. SPS — GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth.NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation.", "prior_body": "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)20232022GAAP net income$1,771 $1,736 Loss on Comanche Unit 3 litigation35 — Workforce reduction expenses72 — Less: tax effect of adjustments(27)— Ongoing earnings$1,851 $1,736 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 — 0.25 Earnings from equity method investments — WYCO0.04 — 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 Twelve Months Ended Dec. 31, 2022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.23 $— $1.23 PSCo1.33 — 1.33 SPS0.64 — 0.64 NSP-Wisconsin0.23 — 0.23 Earnings from equity method investments — WYCO0.04 — 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. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings: (Millions of Dollars)20232022GAAP net income$1,771 $1,736 Loss on Comanche Unit 3 litigation35 — Workforce reduction expenses72 — Less: tax effect of adjustments(27)— Ongoing earnings$1,851 $1,736 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 — 0.25 Earnings from equity method investments — WYCO0.04 — 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 PSCo (a) Regulated utility (a) Total (a) Twelve Months Ended Dec. 31, 2022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.23 $— $1.23 PSCo1.33 — 1.33 SPS0.64 — 0.64 NSP-Wisconsin0.23 — 0.23 Earnings from equity method investments — WYCO0.04 — 0.04 Regulated utility (a)3.47 — 3.47 Xcel Energy Inc. and Other(0.29)— (0.29)Total (a)$3.17 — $3.17 Regulated utility (a) Total (a) (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 26 26 Table of Contents Table of Contents Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments — WYCO0.04 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 litigation0.05 — Workforce reduction expenses0.09 — 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 2022Xcel 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 EPSComponents significantly contributing to changes in EPS:2023 vs. 2022Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS — 2022$3.17 Components of change — 2023 vs. 2022Higher electric revenues, net of electric fuel and purchased power0.07 Lower O&M expenses0.06 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 transported0.03 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 expenses0.09 Loss on Comanche Unit 3 litigation0.05 Ongoing diluted EPS — 2023$3.35 ROE for Xcel Energy and its utility subsidiaries:20232022ROEGAAP ROEOngoing ROEGAAP and Ongoing ROENSP-Minnesota8.82 %9.11 %8.76 %PSCo7.32 7.77 8.23 SPS9.80 9.98 9.36 NSP-Wisconsin10.38 10.67 10.57 Operating Companies8.45 8.79 8.74 Xcel Energy10.33 10.79 10.76 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric 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. Results of OperationsDiluted EPS for Xcel Energy at Dec. 31:20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments — WYCO0.04 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 litigation0.05 — Workforce reduction expenses0.09 — 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 2022Xcel 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 $0.02 per share for 2023 compared to 2022. The increase in ongoing earnings was primarily a result of higher recovery of electric infrastructure investment, partially offset by unfavorable weather and, higher depreciation, O&M expenses and interest charges." }, { "status": "MODIFIED", "current_title": "(Millions of Dollars)Year Ended Dec. 31AverageHighLow2024$— $— $1 $— 2023— — 1 —", "prior_title": "(Millions of Dollars)Year Ended Dec. 31AverageHighLow2023$— $— $1 $— 20222 1 5 —", "similarity_score": 0.81, "confidence": "high", "key_changes": [ "Reworded sentence: \"Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States.\"", "Reworded sentence: \"A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively.\"", "Reworded sentence: \"31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million.\"", "Removed sentence: \"Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value.\"", "Removed sentence: \"Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.\"" ], "current_body": "Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2025 through 2029 enriched nuclear material requirements, which are in various stages of processing in Canada, Europe and the United States. In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota is no longer permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives. A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $7 million and $9 million in 2024 and 2023, respectively. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes. Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million. At Dec. 31, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $24 million. 39 39 39 Table of Contents Table of Contents Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities — 2023$5,327 Components of change — 2024 vs. 2023Higher net income165 Non-cash transactions222 Changes in deferred taxes284 Changes in working capital (783)Changes in net regulatory and other assets and liabilities(574)Cash provided by operating activities — 2024$4,641 Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities — 2023$(5,926)Components of change — 2024 vs. 2023Increased capital expenditures(1,510)Other investing activities8 Cash used in investing activities — 2024$(7,428)Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities —2023$617 Components of change — 2024 vs. 2023Higher long-term debt issuances, net of repayments1,512 Higher proceeds from issuance of common stock847 Higher dividends paid to shareholders(83)Other financing activities(56)Cash provided by financing activities — 2024$2,837 Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023. The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information.Capital RequirementsXcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation. Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.Fair Value MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities — 2023$5,327 Components of change — 2024 vs. 2023Higher net income165 Non-cash transactions222 Changes in deferred taxes284 Changes in working capital (783)Changes in net regulatory and other assets and liabilities(574)Cash provided by operating activities — 2024$4,641 Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers. Xcel Energy conducts credit reviews for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.", "prior_body": "39 39 39 Table of Contents 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 MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities — 2022$3,932 Components of change — 2023 vs. 2022Higher net income35 Non-cash transactions88 Changes in working capital900 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 $1,395 million for 2023 as compared to 2022. The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities — 2022$(4,653)Components of change — 2023 vs. 2022Increased 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. 31Cash provided by financing activities — 2022$666 Components of change — 2023 vs. 2022Higher debt issuances, net of repayments80 Lower proceeds from issuance of common stock(52)Higher dividends paid to shareholders(80)Other financing activities3 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. 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. 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 MeasurementsDerivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.Liquidity and Capital ResourcesCash FlowsOperating Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities — 2022$3,932 Components of change — 2023 vs. 2022Higher net income35 Non-cash transactions88 Changes in working capital900 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 $1,395 million for 2023 as compared to 2022. The increase was largely due to continued collections of prior year deferred net natural gas, fuel and purchased energy costs, as well as the impact of decreased natural gas prices on accounts payable and receivables. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities — 2022$(4,653)Components of change — 2023 vs. 2022Increased 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. 31Cash provided by financing activities — 2022$666 Components of change — 2023 vs. 2022Higher debt issuances, net of repayments80 Lower proceeds from issuance of common stock(52)Higher dividends paid to shareholders(80)Other financing activities3 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." }, { "status": "MODIFIED", "current_title": "Short-Term Borrowings", "prior_title": "Short-Term Borrowings", "similarity_score": 0.808, "confidence": "high", "key_changes": [ "Reworded sentence: \"Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.\"", "Reworded sentence: \"31, 2024Year Ended Dec.\"", "Reworded sentence: \"31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.\"", "Reworded sentence: \"31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively.\"", "Reworded sentence: \"In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks.\"" ], "current_body": "Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements. Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31202420232022Borrowing limit$3,550 $3,550 $3,550 $3,550 Amount outstanding at period end695 695 785 813 Average amount outstanding133 508 491 552 Maximum amount outstanding695 1,314 1,241 1,357 Weighted average interest rate, computed on a daily basis4.77 %5.47 %5.12 %1.47 %Weighted average interest rate at period end4.64 4.64 5.52 4.66 Bilateral Credit Agreement — In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20242023Xcel Energy Inc. (d)59.8 %59.8 %$350 2 NSP-Minnesota47.0 47.7 150 2 NSP-Wisconsin47.1 48.2 N/A1 SPS46.6 46.1 50 2 PSCo45.2 44.8 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2024, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2024:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $235 $1,265 PSCo700 115 585 NSP-Minnesota700 207 493 SPS500 145 355 NSP-Wisconsin150 35 115 Total$3,550 $737 $2,813 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20242023Xcel Energy Inc. (d)59.8 %59.8 %$350 2 NSP-Minnesota47.0 47.7 150 2 NSP-Wisconsin47.1 48.2 N/A1 SPS46.6 46.1 50 2 PSCo45.2 44.8 100 2", "prior_body": "Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements. Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2023Year Ended Dec. 31202320222021Borrowing limit$3,550 $3,550 $3,550 $3,100 Amount outstanding at period end785 785 813 1,005 Average amount outstanding339 491 552 1,399 Maximum amount outstanding785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis5.51 %5.12 %1.47 %0.57 %Weighted average interest rate at period end5.52 5.52 4.66 0.31 Bilateral Credit Agreement — In April 2023, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Terms of Credit Agreements — In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. Bilateral Credit Agreement — In April 2023, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Terms of Credit Agreements — In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. 58 58 58 Table of Contents Table of Contents Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20232022Xcel Energy Inc. (d)59.8 %59.7 %$350 2 NSP-Minnesota47.7 47.7 150 2 NSP-Wisconsin48.2 47.4 N/A1 SPS46.1 45.7 50 2 PSCo44.8 44.0 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2023:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $165 $1,335 PSCo700 349 351 NSP-Minnesota700 180 520 SPS500 75 425 NSP-Wisconsin150 60 90 Total$3,550 $829 $2,721 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2023 and 2022.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20232022Unsecured senior notes0.50 %Oct. 15, 2023$— $500 Unsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes (a)4.60 June 1, 2032700 700 Unsecured senior notes (b)5.45 Aug. 15, 2033800 — Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(8)(7)Unamortized debt issuance cost(36)(35)Current maturities — (500)Total long-term debt$6,136 $5,338 (a)2022 financing.(b)2023 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20232022First mortgage bonds2.60 %May 15, 2023$— $400 First mortgage bonds7.125 July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds (a)4.50 June 1, 2052500 500 First mortgage bonds (b)5.10 May 15, 2053800 — Other long-term debt2 3 Unamortized discount(49)(45)Unamortized debt issuance cost(73)(66)Current maturities— (400)Total long-term debt$7,330 $6,542 (a)2022 financing.(b)2023 financing. Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20232022Xcel Energy Inc. (d)59.8 %59.7 %$350 2 NSP-Minnesota47.7 47.7 150 2 NSP-Wisconsin48.2 47.4 N/A1 SPS46.1 45.7 50 2 PSCo44.8 44.0 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2023, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2023:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $165 $1,335 PSCo700 349 351 NSP-Minnesota700 180 520 SPS500 75 425 NSP-Wisconsin150 60 90 Total$3,550 $829 $2,721 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2023 and 2022.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20232022Xcel Energy Inc. (d)59.8 %59.7 %$350 2 NSP-Minnesota47.7 47.7 150 2 NSP-Wisconsin48.2 47.4 N/A1 SPS46.1 45.7 50 2 PSCo44.8 44.0 100 2" }, { "status": "MODIFIED", "current_title": "Investing Cash Flows", "prior_title": "Investing Cash Flows", "similarity_score": 0.808, "confidence": "high", "key_changes": [ "Reworded sentence: \"31Cash used in investing activities — 2023$(5,926)Components of change — 2024 vs.\"" ], "current_body": "(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities — 2023$(5,926)Components of change — 2024 vs. 2023Increased capital expenditures(1,510)Other investing activities8 Cash used in investing activities — 2024$(7,428) Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.", "prior_body": "(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities — 2022$(4,653)Components of change — 2023 vs. 2022Increased 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." }, { "status": "MODIFIED", "current_title": "Joint Ownership of Generation, Transmission and Gas Facilities", "prior_title": "Joint Ownership of Generation, Transmission and Gas Facilities", "similarity_score": 0.791, "confidence": "high", "key_changes": [ "Reworded sentence: \"31, 2024: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 Total NSP-Minnesota (a) (a)Projects additionally include $10 million in CWIP.\"", "Reworded sentence: \"(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 Total PSCo (a) (a)Projects additionally include $28 million in CWIP.\"", "Reworded sentence: \"57 57 57 Table of Contents Table of Contents\"" ], "current_body": "The utility subsidiaries’ jointly owned assets as of Dec. 31, 2024: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 Total NSP-Minnesota (a) (a)Projects additionally include $10 million in CWIP. Projects additionally include $10 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $30 37 %CapX2020169 44 80 Total NSP-Wisconsin (a)$348 $74 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 (a)Projects additionally include $28 million in CWIP.Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $30 37 %CapX2020169 44 80 Total NSP-Wisconsin (a)$348 $74 Total NSP-Wisconsin (a) (a)Projects additionally include $1 million in CWIP. Projects additionally include $1 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 Total PSCo (a) (a)Projects additionally include $28 million in CWIP. Projects additionally include $28 million in CWIP. Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. 57 57 57 Table of Contents Table of Contents", "prior_body": "The utility subsidiaries’ jointly owned assets as of Dec. 31, 2023: (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 Total NSP-Minnesota (a) (a)Projects additionally include $2 million in CWIP. Projects additionally include $2 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 Total NSP-Wisconsin (a) (a)Projects additionally include $1 million in CWIP. Projects additionally include $1 million in CWIP. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 (a)Projects additionally include $18 million in CWIP.Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. (Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 Total PSCo (a) (a)Projects additionally include $18 million in CWIP. Projects additionally include $18 million in CWIP. Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. 56 56 56 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "Xcel Energy Inc. and Other Results", "prior_title": "Xcel Energy Inc. and Other Results", "similarity_score": 0.784, "confidence": "high", "key_changes": [ "Reworded sentence: \"and its nonregulated businesses: (Millions of Dollars)20242023Xcel Energy Inc.\"" ], "current_body": "Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars)20242023Xcel Energy Inc. financing costs$(223)$(174)Xcel Energy Inc. taxes and other results (a)38 1 Total Xcel Energy Inc. and other costs$(185)$(173) Xcel Energy Inc. taxes and other results (a) (Diluted Earnings (Loss) Per Share)20242023Xcel Energy Inc. financing costs$(0.40)$(0.32)Xcel Energy Inc. taxes and other results (a)0.07 0.01 Total Xcel Energy Inc. and other costs$(0.33)$(0.31) Xcel Energy Inc. taxes and other results (a) (a)Amounts include gain from open market debt repurchases in 2024. Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.", "prior_body": "Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses: (Millions of Dollars)20232022Xcel Energy Inc. financing costs$(174)$(153)Venture Holdings (a)3 5 Xcel Energy Inc. taxes and other results(2)(12)Total Xcel Energy Inc. and other costs$(173)$(160) Venture Holdings (a) (Diluted Earnings (Loss) Per Share)20232022Xcel Energy Inc. financing costs$(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) Venture Holdings (a) (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." }, { "status": "MODIFIED", "current_title": "Results of Operations", "prior_title": "Results of Operations", "similarity_score": 0.784, "confidence": "high", "key_changes": [ "Reworded sentence: \"31: Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments — WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc.\"" ], "current_body": "Diluted EPS for Xcel Energy at Dec. 31: Diluted Earnings (Loss) Per Share20242023NSP-Minnesota$1.41 $1.28 PSCo1.39 1.26 SPS0.70 0.70 NSP-Wisconsin0.24 0.25 Earnings from equity method investments — WYCO0.03 0.04 Regulated utility (a)3.76 3.52 Xcel Energy Inc. and Other(0.33)(0.31)GAAP Diluted EPS (a)3.44 3.21 Loss on Comanche Unit 3 litigation— 0.05 Workforce reduction expenses— 0.09 Sherco Unit 3 2011 outage refunds0.06 — Ongoing Diluted EPS (a)$3.50 $3.35 Regulated utility (a) GAAP Diluted EPS (a) Ongoing Diluted EPS (a) (a)Amounts may not add due to rounding. Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.", "prior_body": "Diluted EPS for Xcel Energy at Dec. 31: 20232022Diluted Earnings (Loss) Per ShareGAAP Diluted EPSGAAP Diluted EPSNSP-Minnesota$1.28 $1.23 PSCo1.26 1.33 SPS0.70 0.64 NSP-Wisconsin0.25 0.23 Earnings from equity method investments — WYCO0.04 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 litigation0.05 — Workforce reduction expenses0.09 — Ongoing Diluted EPS (a)$3.35 $3.17 Regulated utility (a) GAAP Diluted EPS (a) Ongoing Diluted EPS (a) (a)Amounts may not add due to rounding. Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors." }, { "status": "MODIFIED", "current_title": "Loss Contingencies – Wildfires", "prior_title": "Loss Contingencies – Marshall Fire", "similarity_score": 0.782, "confidence": "high", "key_changes": [ "Reworded sentence: \"The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty.\"", "Reworded sentence: \"Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses.\"", "Reworded sentence: \"Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered.\"" ], "current_body": "The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 12 accompanying the consolidated financial statements for additional information.", "prior_body": "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." }, { "status": "MODIFIED", "current_title": "Our utility operations are subject to long-term planning and project risks.", "prior_title": "Our utility operations are subject to long-term planning and project risks.", "similarity_score": 0.753, "confidence": "high", "key_changes": [ "Reworded sentence: \"Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence.\"", "Reworded sentence: \"Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk.\"" ], "current_body": "Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines. In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. Our utilities have physical and financial risks associated with wildfires.In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Wildfires could jeopardize Xcel Energy’s electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.", "prior_body": "Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines. In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to commodity risks and other risks associated with energy markets and energy production.A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments negatively impacts our cash flows and results of operations.We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends. Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations. Due to the uncertainty involved in price movements and potential deviation from historical pricing, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, Xcel Energy cannot fully assure that its controls will be effective against all potential risks. If such programs and procedures are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate." }, { "status": "MODIFIED", "current_title": "4. Regulatory Assets and Liabilities", "prior_title": "Dec. 31, 2022 (a)", "similarity_score": 0.751, "confidence": "high", "key_changes": [ "Reworded sentence: \"Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates.\"", "Reworded sentence: \"Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec.\"", "Reworded sentence: \"(e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions..\"", "Reworded sentence: \"58 58 58 Table of Contents Table of Contents 5.\"", "Reworded sentence: \"31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations.\"" ], "current_body": "Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2024Dec. 31, 2023Regulatory AssetsCurrentNoncurrentCurrentNoncurrentPension and retiree medical obligations11Various$39 $1,167 $27 $1,106 Net AROs1, 12Various— 387 — 316 Recoverable deferred taxes on AFUDCPlant lives— 368 — 332 Depreciation differencesVarious17 250 17 189 Excess deferred taxes — TCJA 7Various10 184 10 198 MISO capacity revenue trackerOne to two years63 45 36 26 Environmental remediation costs1, 12Various13 39 15 94 Prairie Island extended power uprate10 years4 34 4 38 Conservation programs (a)1One to two years20 30 19 54 Purchased power contract costsTerm of related contract5 28 4 40 Benson biomass PPA termination and asset purchaseFour years10 26 10 36 Deferred natural gas, electric, steam energy/fuel costsOne to two years99 25 239 80 Sales true-up and revenue decouplingVarious60 23 7 33 Nuclear refueling outage costs1One to two years51 20 43 19 Gas pipeline inspection and remediation costsOne to two years47 9 40 25 Renewable resources and environmental initiativesOne to two years34 4 38 5 Other Various89 210 102 207 Total regulatory assets$561 $2,849 $611 $2,798 Excess deferred taxes — TCJA One to two years One two Conservation programs (a) One to two years One two Four years Four One to two years One two One to two years One two One to two years One two One to two years One two Other (a)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2024Dec. 31, 2023Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (a)7Various$7 $2,888 $7 $3,015 Plant removal costs1, 12Various— 2,208 — 1,984 Effects of regulation on employee benefit costs (b)11Various— 259 — 253 Renewable resources and environmental initiativesVarious16 232 9 188 Net AROs (c)Various— 161 — 90 ITC deferrals1Various— 70 1 60 IRA deferralOne to three years3 37 — — Deferred natural gas, electric, steam energy/fuel costsOne to two years480 12 220 — Contract valuation adjustments (d)1, 10Less than one year89 — 56 — Conservation programs (e)1Less than one year52 — 47 — Other Various205 143 188 237 Total regulatory liabilities (f)$852 $6,010 $528 $5,827 Deferred income tax adjustments and TCJA refunds (a) Effects of regulation on employee benefit costs (b) Net AROs (c) ITC deferrals One to three years One three One to two years One two Contract valuation adjustments (d) Less than one year one Conservation programs (e) Less than one year one Total regulatory liabilities (f) (a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.. (f)Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities. Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities. Xcel Energy’s regulatory assets not earning a return include past expenditures of $892 million and $1,085 million at Dec. 31, 2024 and 2023 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return. 58 58 58 Table of Contents Table of Contents 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31202420232022Borrowing limit$3,550 $3,550 $3,550 $3,550 Amount outstanding at period end695 695 785 813 Average amount outstanding133 508 491 552 Maximum amount outstanding695 1,314 1,241 1,357 Weighted average interest rate, computed on a daily basis4.77 %5.47 %5.12 %1.47 %Weighted average interest rate at period end4.64 4.64 5.52 4.66 Bilateral Credit Agreement — In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027.Features of the credit facilities:Debt-to-Total Capitalization Ratio (a)Amount Facility May Be Increased (millions of dollars) (b)Additional Periods for Which a One-Year Extension May Be Requested (c)20242023Xcel Energy Inc. (d)59.8 %59.8 %$350 2 NSP-Minnesota47.0 47.7 150 2 NSP-Wisconsin47.1 48.2 N/A1 SPS46.6 46.1 50 2 PSCo45.2 44.8 100 2 (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions.(c)All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2024, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2024:(Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $235 $1,265 PSCo700 115 585 NSP-Minnesota700 207 493 SPS500 145 355 NSP-Wisconsin150 35 115 Total$3,550 $737 $2,813 (a)These credit facilities mature in September 2027.(b)Includes outstanding commercial paper and letters of credit.All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023.Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31202420232022Borrowing limit$3,550 $3,550 $3,550 $3,550 Amount outstanding at period end695 695 785 813 Average amount outstanding133 508 491 552 Maximum amount outstanding695 1,314 1,241 1,357 Weighted average interest rate, computed on a daily basis4.77 %5.47 %5.12 %1.47 %Weighted average interest rate at period end4.64 4.64 5.52 4.66 Bilateral Credit Agreement — In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027.", "prior_body": "Net AROs (b) Excess deferred taxes — TCJA One to 12 years One One to three years One three Conservation programs (c) One to two years One two 11 years Five years Five One to two years One two One to two years One two One to two years One two Contract valuation adjustments (d) One to two years One two One to two years One two One to two years One two (a)Prior period amounts have been reclassified to conform with current year presentation. Prior period amounts have been reclassified to conform with current year presentation. (b)The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. (c)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. 57 57 57 Table of Contents Table of Contents Components of regulatory liabilities: (Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2023Dec. 31, 2022Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentDeferred income tax adjustments and TCJA refunds (a)7Various$7 $3,015 $9 $3,110 Plant removal costs1, 12Various— 1,984 — 1,819 Effects of regulation on employee benefit costs (b)Various— 253 — 247 Renewable resources and environmental initiativesVarious9 188 6 173 Net AROs (c)Various— 90 — — Sales true-up and revenue decouplingTwo years18 76 — 77 ITC deferrals1Various1 60 1 61 LP&L departure paymentUp to 10 years33 33 — — Formula ratesOne to two years29 18 32 17 DOE settlementOne to two years18 6 12 3 Deferred natural gas, electric, steam energy/fuel costsLess than one year220 — 39 — Contract valuation adjustments (d)1, 10Less than one year56 — 175 1 Conservation programs (e)1Less than one year47 — 72 — OtherVarious90 104 72 61 Total regulatory liabilities (f)$528 $5,827 $418 $5,569 Deferred income tax adjustments and TCJA refunds (a) Effects of regulation on employee benefit costs (b) Net AROs (c) Two years Two ITC deferrals Up to 10 years One to two years One two One to two years One two Less than one year one Contract valuation adjustments (d) Less than one year one Conservation programs (e) Less than one year one Total regulatory liabilities (f) (a)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. (b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (f)Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. Xcel Energy’s regulatory assets not earning a return include past expenditures of $1,085 million and $1,020 million at Dec. 31, 2023 and 2022 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2023Year Ended Dec. 31202320222021Borrowing limit$3,550 $3,550 $3,550 $3,100 Amount outstanding at period end785 785 813 1,005 Average amount outstanding339 491 552 1,399 Maximum amount outstanding785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis5.51 %5.12 %1.47 %0.57 %Weighted average interest rate at period end5.52 5.52 4.66 0.31 Bilateral Credit Agreement — In April 2023, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Terms of Credit Agreements — In September 2022, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. 5. Borrowings and Other Financing InstrumentsShort-Term BorrowingsShort-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.Commercial paper and other borrowings outstanding:(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2023Year Ended Dec. 31202320222021Borrowing limit$3,550 $3,550 $3,550 $3,100 Amount outstanding at period end785 785 813 1,005 Average amount outstanding339 491 552 1,399 Maximum amount outstanding785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis5.51 %5.12 %1.47 %0.57 %Weighted average interest rate at period end5.52 5.52 4.66 0.31" }, { "status": "MODIFIED", "current_title": "Capital Sources", "prior_title": "Capital Sources", "similarity_score": 0.737, "confidence": "medium", "key_changes": [ "Reworded sentence: \"Credit Facility Agreements — As of Feb.\"", "Removed sentence: \"20, 2024, Xcel Energy Inc.\"", "Removed sentence: \"and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 43 107 8 115 Total$3,550 $1,159 $2,391 $29 $2,420 Facility (a) Drawn (b) (a)Credit facilities expire in September 2027.\"", "Removed sentence: \"(b)Includes outstanding commercial paper and letters of credit.\"", "Reworded sentence: \"31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively.\"" ], "current_body": "Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments. Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts. Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are: •$1.50 billion for Xcel Energy Inc. •$700 million for PSCo. •$700 million for NSP-Minnesota. •$500 million for SPS. •$150 million for NSP-Wisconsin. See Note 5 to the consolidated financial statements for further information. Credit Facility Agreements — As of Feb. 24, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars)Facility (a)Drawn (b)AvailableCashLiquidityXcel Energy Inc.$1,500 $660 $840 $25 $865 PSCo700 101 599 10 609 NSP-Minnesota700 375 325 7 332 SPS500 255 245 7 252 NSP-Wisconsin150 27 123 3 126 Total$3,550 $1,418 $2,132 $52 $2,184 Facility (a) Drawn (b) (a)Credit facilities expire in September 2027. (b)Includes outstanding commercial paper and letters of credit. Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval. Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2024 and 2023, Xcel Energy had approximately 574 million shares and 555 million shares of common stock outstanding, respectively. Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval. Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program, forward equity agreements or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors. 42 42 42 Table of Contents Table of Contents Planned Financing Activity — Xcel Energy’s 2025 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Expected TenorAnticipated TimingXcel Energy Inc.Senior Unsecured Notes$1,000 10 YearFirst QuarterPSCoFirst Mortgage Bonds2,000 10 Year & 30 YearSecond & Third QuarterNSP-MinnesotaFirst Mortgage Bonds1,100 10 Year & 30 YearFirst & Third QuarterSPSFirst Mortgage Bonds45030 YearSecond QuarterNSP-WisconsinFirst Mortgage Bonds25030 YearSecond QuarterSee Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2025 Earnings Guidance — Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)Key assumptions as compared with 2024 actual levels unless noted:•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.•Normal weather patterns for the year.•Weather-normalized retail electric sales are projected to increase ~3%.•Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs).•O&M expenses are projected to increase ~3%.•Depreciation expense is projected to increase approximately $210 million to $220 million.•Property taxes are projected to increase $55 million to $65 million. •Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income. •AFUDC - equity is projected to increase $110 million to $120 million.(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:• Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).• Deliver annual dividend increases of 4% to 6%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Planned Financing Activity — Xcel Energy’s 2025 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Expected TenorAnticipated TimingXcel Energy Inc.Senior Unsecured Notes$1,000 10 YearFirst QuarterPSCoFirst Mortgage Bonds2,000 10 Year & 30 YearSecond & Third QuarterNSP-MinnesotaFirst Mortgage Bonds1,100 10 Year & 30 YearFirst & Third QuarterSPSFirst Mortgage Bonds45030 YearSecond QuarterNSP-WisconsinFirst Mortgage Bonds25030 YearSecond QuarterSee Note 5 to the consolidated financial statements for further information.Earnings Guidance and Long-Term EPS and Dividend Growth Rate ObjectivesXcel Energy 2025 Earnings Guidance — Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)Key assumptions as compared with 2024 actual levels unless noted:•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.•Normal weather patterns for the year.•Weather-normalized retail electric sales are projected to increase ~3%.•Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs).•O&M expenses are projected to increase ~3%.•Depreciation expense is projected to increase approximately $210 million to $220 million.•Property taxes are projected to increase $55 million to $65 million. •Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income. •AFUDC - equity is projected to increase $110 million to $120 million.(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS. Planned Financing Activity — Xcel Energy’s 2025 financing plans reflect the following: IssuerSecurityAmount (Millions of Dollars)Expected TenorAnticipated TimingXcel Energy Inc.Senior Unsecured Notes$1,000 10 YearFirst QuarterPSCoFirst Mortgage Bonds2,000 10 Year & 30 YearSecond & Third QuarterNSP-MinnesotaFirst Mortgage Bonds1,100 10 Year & 30 YearFirst & Third QuarterSPSFirst Mortgage Bonds45030 YearSecond QuarterNSP-WisconsinFirst Mortgage Bonds25030 YearSecond Quarter See Note 5 to the consolidated financial statements for further information.", "prior_body": "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)AvailableCashLiquidityXcel Energy Inc.$1,500 $486 $1,014 $2 $1,016 PSCo700 258 442 6 448 NSP-Minnesota700 273 427 10 437 SPS500 99 401 3 404 NSP-Wisconsin150 43 107 8 115 Total$3,550 $1,159 $2,391 $29 $2,420 Facility (a) Drawn (b) (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 42 42 Table of Contents Table of Contents Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Anticipated TimingExpected TenorXcel Energy Inc.Senior Unsecured Notes$900 First Quarter10 YearPSCoFirst Mortgage Bonds1,200 Second Quarter10 Year and 30 YearNSP-MinnesotaFirst Mortgage Bonds700First Quarter30 YearSPSFirst Mortgage Bonds550Second Quarter30 YearNSP-WisconsinFirst Mortgage Bonds400Second Quarter30 YearLong-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 ObjectivesXcel 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 RISKSee the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect the following:IssuerSecurityAmount (Millions of Dollars)Anticipated TimingExpected TenorXcel Energy Inc.Senior Unsecured Notes$900 First Quarter10 YearPSCoFirst Mortgage Bonds1,200 Second Quarter10 Year and 30 YearNSP-MinnesotaFirst Mortgage Bonds700First Quarter30 YearSPSFirst Mortgage Bonds550Second Quarter30 YearNSP-WisconsinFirst Mortgage Bonds400Second Quarter30 YearLong-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 ObjectivesXcel 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. Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect the following: IssuerSecurityAmount (Millions of Dollars)Anticipated TimingExpected TenorXcel Energy Inc.Senior Unsecured Notes$900 First Quarter10 YearPSCoFirst Mortgage Bonds1,200 Second Quarter10 Year and 30 YearNSP-MinnesotaFirst Mortgage Bonds700First Quarter30 YearSPSFirst Mortgage Bonds550Second Quarter30 YearNSP-WisconsinFirst Mortgage Bonds400Second Quarter30 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." }, { "status": "MODIFIED", "current_title": "Annual weather-normalized and leap year adjusted electric sales growth (decline)", "prior_title": "Annual weather-normalized electric sales growth (decline)", "similarity_score": 0.732, "confidence": "medium", "key_changes": [ "Reworded sentence: \"•NSP-Minnesota — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers.\"" ], "current_body": "•NSP-Minnesota — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by a 1.4% increase in customers. The decline in C&I sales was due to lower use per customer, particularly in the manufacturing sector. •PSCo — Residential sales increased due to a 1.4% increase in customers, partially offset by a 0.7% decrease in use per customer. The decline in C&I sales was attributable to decreased use per customer, particularly in the wholesale trade and mining. •SPS — Residential sales declined due to a 2.2% decrease in use per customer partially offset by a 0.7% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining. •NSP-Wisconsin — Residential sales declined due to a 2.7% decrease in use per customer, offset by a 1.0% increase in customers. The C&I sales decline was associated with lower use per customer, experienced particularly in the professional services and manufacturing sectors.", "prior_body": "•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." }, { "status": "MODIFIED", "current_title": "2023 Comparison with 2022", "prior_title": "2022 Comparison with 2021", "similarity_score": 0.726, "confidence": "medium", "key_changes": [ "Reworded sentence: \"31, 2023 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb.\"" ], "current_body": "A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2022 to Dec. 31, 2023 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb. 21, 2024. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.", "prior_body": "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." }, { "status": "MODIFIED", "current_title": "2024 Comparison with 2023", "prior_title": "2023 Comparison with 2022", "similarity_score": 0.717, "confidence": "medium", "key_changes": [ "Reworded sentence: \"Xcel Energy — GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023.\"", "Reworded sentence: \"NSP-Minnesota — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023.\"", "Reworded sentence: \"However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.\"" ], "current_body": "Xcel Energy — GAAP earnings were $3.44 per share compared to $3.21 per share in 2023 and ongoing earnings were $3.50 per share in 2024, compared with $3.35 per share in 2023. The change in EPS was driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues). NSP-Minnesota — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.15 per share for 2024 compared to 2023. Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation and interest charges. PSCo — GAAP earnings increased $0.13 per share and ongoing earnings increased $0.06 per share for 2024. Higher ongoing earnings primarily reflects higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation, O&M and interest charges. SPS — GAAP earnings were flat and ongoing earnings decreased $0.01 per share for 2024. Ongoing earnings were impacted by increased depreciation, O&M and interest charges, largely offset by regulatory rate outcomes and sales growth. NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for 2024. The decrease in ongoing earnings was primarily a result of higher depreciation. Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.Changes in Diluted EPSComponents significantly contributing to changes in 2024 EPS compared with 2023:Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS — 2023$3.21 Components of change — 2024 vs. 2023Electric regulatory rate outcomes and riders0.73 Higher other income, net0.16 Natural gas regulatory rate outcomes and riders0.14 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Higher depreciation and amortization(0.40)Interest charges, net of AFUDC - debt(0.24)Higher O&M expenses(0.13)Sherco Unit 3 2011 outage refunds(0.06)Other, net(0.11)GAAP diluted EPS — 2024$3.44 Sherco Unit 3 2011 outage refunds0.06 Ongoing diluted EPS — 2024$3.50 ROE for Xcel Energy and its utility subsidiaries:20242023ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.07 %9.46 %8.82 %9.11 %PSCo7.63 7.63 7.32 7.77 SPS9.57 9.57 9.80 9.98 NSP-Wisconsin8.98 8.98 10.38 10.67 Utility Subsidiaries8.55 8.69 8.45 8.79 Xcel Energy10.42 10.61 10.33 10.79 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction. Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings for 2024 is largely due to higher debt levels and increased interest rates, partially offset by a gain on debt repurchases.", "prior_body": "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 EPSComponents significantly contributing to changes in EPS:2023 vs. 2022Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS — 2022$3.17 Components of change — 2023 vs. 2022Higher electric revenues, net of electric fuel and purchased power0.07 Lower O&M expenses0.06 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 transported0.03 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 expenses0.09 Loss on Comanche Unit 3 litigation0.05 Ongoing diluted EPS — 2023$3.35 ROE for Xcel Energy and its utility subsidiaries:20232022ROEGAAP ROEOngoing ROEGAAP and Ongoing ROENSP-Minnesota8.82 %9.11 %8.76 %PSCo7.32 7.77 8.23 SPS9.80 9.98 9.36 NSP-Wisconsin10.38 10.67 10.57 Operating Companies8.45 8.79 8.74 Xcel Energy10.33 10.79 10.76 Statement of Income AnalysisThe following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric 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. 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." }, { "status": "MODIFIED", "current_title": "Pending and Recently Concluded Regulatory Proceedings", "prior_title": "Pending and Recently Concluded Regulatory Proceedings", "similarity_score": 0.711, "confidence": "medium", "key_changes": [ "Reworded sentence: \"2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%.\"", "Reworded sentence: \"The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC.\"", "Reworded sentence: \"NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas.\"", "Reworded sentence: \"Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.\"", "Reworded sentence: \"NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas.\"" ], "current_body": "2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).", "prior_body": "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 30 30 Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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 JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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 ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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. 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." }, { "status": "MODIFIED", "current_title": "Regulatory Accounting", "prior_title": "Regulatory Accounting", "similarity_score": 0.699, "confidence": "medium", "key_changes": [ "Reworded sentence: \"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.\"", "Reworded sentence: \"31, 2024, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets.\"", "Reworded sentence: \"Pension assumptions are continually reviewed.\"" ], "current_body": "Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income. Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2024 and 2023, Xcel Energy had regulatory assets of $3.4 billion and $3.4 billion, respectively and regulatory liabilities of $6.9 billion and $6.4 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2024, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information.Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows. As of Dec. 31, 2024 and 2023, Xcel Energy had regulatory assets of $3.4 billion and $3.4 billion, respectively and regulatory liabilities of $6.9 billion and $6.4 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2024, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information.", "prior_body": "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 36 36 Table of Contents Table of Contents Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.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. Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.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." }, { "status": "MODIFIED", "current_title": "Critical Audit Matters", "prior_title": "Critical Audit Matter", "similarity_score": 0.693, "confidence": "medium", "key_changes": [ "Reworded sentence: \"The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.\"" ], "current_body": "The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.", "prior_body": "The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 45 45 45 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "Nuclear Power Operations", "prior_title": "Nuclear Power Operations", "similarity_score": 0.692, "confidence": "medium", "key_changes": [ "Reworded sentence: \"Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas.\"", "Added sentence: \"Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.\"", "Added sentence: \"Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No.\"", "Added sentence: \"DPR-22, Accession No.\"", "Added sentence: \"NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054.\"" ], "current_body": "Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use. NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs. Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable. High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site. Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2. In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050. In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.", "prior_body": "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 JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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 ProceedingsWisconsin 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." }, { "status": "MODIFIED", "current_title": "Financing Cash Flows", "prior_title": "Financing Cash Flows", "similarity_score": 0.675, "confidence": "medium", "key_changes": [ "Reworded sentence: \"31Cash provided by financing activities —2023$617 Components of change — 2024 vs.\"", "Removed sentence: \"40 40 40 Table of Contents Table of Contents\"" ], "current_body": "(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities —2023$617 Components of change — 2024 vs. 2023Higher long-term debt issuances, net of repayments1,512 Higher proceeds from issuance of common stock847 Higher dividends paid to shareholders(83)Other financing activities(56)Cash provided by financing activities — 2024$2,837 Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023. The increase was largely related to additional debt and common stock issuances to fund capital investment. See Note 5 to the consolidated financial statements for further information.", "prior_body": "(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities — 2022$666 Components of change — 2023 vs. 2022Higher debt issuances, net of repayments80 Lower proceeds from issuance of common stock(52)Higher dividends paid to shareholders(80)Other financing activities3 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 40 40 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "CONSOLIDATED STATEMENTS OF CASH FLOWS", "prior_title": "CONSOLIDATED STATEMENTS OF CASH FLOWS", "similarity_score": 0.671, "confidence": "medium", "key_changes": [ "Reworded sentence: \"31 202420232022Operating activities Net income$1,936 $1,771 $1,736 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,769 2,471 2,436 Nuclear fuel amortization106 96 118 Deferred income taxes225 (59)(140)Allowance for equity funds used during construction(168)(91)(75)Earnings from equity method investments(19)(35)(36)Dividends from equity method investments34 35 37 Provision for bad debts47 79 73 Share-based compensation expense33 25 20 Changes in operating assets and liabilities:Accounts receivable19 (27)(429)Accrued unbilled revenues21 252 (243)Inventories(140)(98)(203)Other current assets(139)86 (58)Accounts payable37 (149)195 Net regulatory assets and liabilities436 911 570 Other current liabilities(317)200 102 Pension and other employee benefit obligations(89)17 (49)Other, net(150)(157)(122)Net cash provided by operating activities4,641 5,327 3,932 Investing activitiesCapital/construction expenditures(7,364)(5,854)(4,638)Purchase of investment securities(998)(994)(1,332)Proceeds from the sale of investment securities961 959 1,297 Other, net(27)(37)20 Net cash used in investing activities(7,428)(5,926)(4,653)Financing activitiesRepayments of short-term borrowings, net(90)(28)(192)Proceeds from issuances of long-term debt3,647 2,630 2,164 Repayments of long-term debt(656)(1,151)(601)Proceeds from issuance of common stock1,117 270 322 Dividends paid(1,175)(1,092)(1,012)Other, net(6)(12)(15)Net cash provided by financing activities2,837 617 666 Net change in cash and cash equivalents50 18 (55)Cash, cash equivalents and restricted cash at beginning of period129 111 166 Cash, cash equivalents and restricted cash at end of period$179 $129 $111 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(1,131)$(945)$(887)Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers588 92 (15)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$964 $553 $626 Inventory transfers to property, plant and equipment258 197 78 Operating lease right-of-use assets138 238 141 Allowance for equity funds used during construction168 91 75 Issuance of common stock for reinvested dividends and/or equity awards68 64 57 See Notes to Consolidated Financial Statements 50 50 50 Table of Contents Table of Contents\"" ], "current_body": "(amounts in millions) Year Ended Dec. 31 202420232022Operating activities Net income$1,936 $1,771 $1,736 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,769 2,471 2,436 Nuclear fuel amortization106 96 118 Deferred income taxes225 (59)(140)Allowance for equity funds used during construction(168)(91)(75)Earnings from equity method investments(19)(35)(36)Dividends from equity method investments34 35 37 Provision for bad debts47 79 73 Share-based compensation expense33 25 20 Changes in operating assets and liabilities:Accounts receivable19 (27)(429)Accrued unbilled revenues21 252 (243)Inventories(140)(98)(203)Other current assets(139)86 (58)Accounts payable37 (149)195 Net regulatory assets and liabilities436 911 570 Other current liabilities(317)200 102 Pension and other employee benefit obligations(89)17 (49)Other, net(150)(157)(122)Net cash provided by operating activities4,641 5,327 3,932 Investing activitiesCapital/construction expenditures(7,364)(5,854)(4,638)Purchase of investment securities(998)(994)(1,332)Proceeds from the sale of investment securities961 959 1,297 Other, net(27)(37)20 Net cash used in investing activities(7,428)(5,926)(4,653)Financing activitiesRepayments of short-term borrowings, net(90)(28)(192)Proceeds from issuances of long-term debt3,647 2,630 2,164 Repayments of long-term debt(656)(1,151)(601)Proceeds from issuance of common stock1,117 270 322 Dividends paid(1,175)(1,092)(1,012)Other, net(6)(12)(15)Net cash provided by financing activities2,837 617 666 Net change in cash and cash equivalents50 18 (55)Cash, cash equivalents and restricted cash at beginning of period129 111 166 Cash, cash equivalents and restricted cash at end of period$179 $129 $111 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(1,131)$(945)$(887)Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers588 92 (15)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$964 $553 $626 Inventory transfers to property, plant and equipment258 197 78 Operating lease right-of-use assets138 238 141 Allowance for equity funds used during construction168 91 75 Issuance of common stock for reinvested dividends and/or equity awards68 64 57 See Notes to Consolidated Financial Statements 50 50 50 Table of Contents Table of Contents", "prior_body": "(amounts in millions) Year Ended Dec. 31 202320222021Operating activities Net income$1,771 $1,736 $1,597 Adjustments to reconcile net income to cash provided by operating activities:Depreciation and amortization2,471 2,436 2,143 Nuclear fuel amortization96 118 114 Deferred income taxes(59)(140)(79)Allowance for equity funds used during construction(91)(75)(73)Earnings from equity method investments(35)(36)(62)Dividends from equity method investments35 37 42 Provision for bad debts79 73 60 Share-based compensation expense25 20 31 Changes in operating assets and liabilities:Accounts receivable(27)(429)(164)Accrued unbilled revenues252 (243)(149)Inventories(98)(203)(126)Other current assets86 (58)(34)Accounts payable(149)195 138 Net regulatory assets and liabilities911 570 (973)Other current liabilities200 102 (1)Pension and other employee benefit obligations17 (49)(135)Other, net(157)(122)(140)Net cash provided by operating activities5,327 3,932 2,189 Investing activitiesCapital/construction expenditures(5,854)(4,638)(4,244)Purchase of investment securities(994)(1,332)(757)Proceeds from the sale of investment securities959 1,297 743 Other, net(37)20 (29)Net cash used in investing activities(5,926)(4,653)(4,287)Financing activities(Repayments of) proceeds from short-term borrowings, net(28)(192)421 Proceeds from issuances of long-term debt2,630 2,164 2,710 Repayments of long-term debt(1,151)(601)(417)Proceeds from issuance of common stock270 322 366 Dividends paid(1,092)(1,012)(935)Other, net(12)(15)(10)Net cash provided by financing activities617 666 2,135 Net change in cash and cash equivalents18 (55)37 Cash, cash equivalents and restricted cash at beginning of period111 166 129 Cash, cash equivalents and restricted cash at end of period$129 $111 $166 Supplemental disclosure of cash flow information:Cash paid for interest (net of amounts capitalized)$(945)$(887)$(788)Cash received (paid) for income taxes, net92 (15)(4)Supplemental disclosure of non-cash investing and financing transactions:Accrued property, plant and equipment additions$553 $626 $501 Inventory transfers to property, plant and equipment197 78 87 Operating lease right-of-use assets238 141 8 Allowance for equity funds used during construction91 75 73 Issuance of common stock for reinvested dividends and/or equity awards64 57 60 See Notes to Consolidated Financial Statements 49 49 49 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "Recently Issued", "prior_title": "Major classes of property, plant and equipment", "similarity_score": 0.656, "confidence": "medium", "key_changes": [ "Reworded sentence: \"Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments.\"", "Reworded sentence: \"Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec.\"" ], "current_body": "Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements. Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements. Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disaggregated disclosure of income statement expenses for public business entities. The ASU is effective for annual periods beginning after Dec. 15, 2026. Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance. 56 56 56 Table of Contents Table of Contents 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Property, plant and equipment, netElectric plant$56,791 $52,494 Natural gas plant9,834 9,080 Common and other property3,515 3,190 Plant to be retired (a)1,793 2,055 CWIP4,720 2,873 Total property, plant and equipment76,653 69,692 Less accumulated depreciation(19,852)(18,399)Nuclear fuel3,491 3,337 Less accumulated amortization(3,094)(2,988)Property, plant and equipment, net$57,198 $51,642 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process. Amounts are presented net of accumulated depreciation.Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries’ jointly owned assets as of Dec. 31, 2024:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 (a)Projects additionally include $10 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$179 $30 37 %CapX2020169 44 80 Total NSP-Wisconsin (a)$348 $74 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$158 $117 76 %Hayden Unit 2152 93 37 Hayden common facilities45 33 53 Craig Units 1 and 282 58 10 Craig common facilities40 27 7 Comanche Unit 3933 212 67 Comanche common facilities29 5 77 Electric transmission:Transmission and other facilities190 75 VariousGas transmission:Rifle, CO to Avon, CO28 10 60 Gas transmission compressor8 3 50 Total PSCo (a)$1,665 $633 (a)Projects additionally include $28 million in CWIP.Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing. 3. Property, Plant and EquipmentMajor classes of property, plant and equipment(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023Property, plant and equipment, netElectric plant$56,791 $52,494 Natural gas plant9,834 9,080 Common and other property3,515 3,190 Plant to be retired (a)1,793 2,055 CWIP4,720 2,873 Total property, plant and equipment76,653 69,692 Less accumulated depreciation(19,852)(18,399)Nuclear fuel3,491 3,337 Less accumulated amortization(3,094)(2,988)Property, plant and equipment, net$57,198 $51,642 (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process. Amounts are presented net of accumulated depreciation.Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries’ jointly owned assets as of Dec. 31, 2024:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$636 $499 59 %Sherco common facilities189 128 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 3 50 CapX2020855 160 51 Total NSP-Minnesota (a)$1,745 $798 (a)Projects additionally include $10 million in CWIP.", "prior_body": "(Millions of Dollars)Dec. 31, 2023Dec. 31, 2022Property, plant and equipment, netElectric plant$52,494 $49,639 Natural gas plant9,080 8,514 Common and other property3,190 2,970 Plant to be retired (a)2,055 2,217 CWIP2,873 2,124 Total property, plant and equipment69,692 65,464 Less accumulated depreciation(18,399)(17,502)Nuclear fuel3,337 3,183 Less accumulated amortization(2,988)(2,892)Property, plant and equipment, net$51,642 $48,253 Plant to be retired (a) (a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net of accumulated depreciation. (a) 55 55 55 Table of Contents Table of Contents Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries’ jointly owned assets as of Dec. 31, 2023:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 (a)Projects additionally include $2 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 (a)Projects additionally include $1 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedPSCoElectric generation:Hayden Unit 1$157 $108 76 %Hayden Unit 2151 87 37 Hayden common facilities44 31 53 Craig Units 1 and 282 55 10 Craig common facilities39 25 7 Comanche Unit 3916 191 67 Comanche common facilities29 4 77 Electric transmission:Transmission and other facilities189 75 VariousGas transmission:Rifle, CO to Avon, CO28 9 60 Gas transmission compressor8 2 50 Total PSCo (a)$1,643 $587 (a)Projects additionally include $18 million in CWIP.Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing. Joint Ownership of Generation, Transmission and Gas FacilitiesThe utility subsidiaries’ jointly owned assets as of Dec. 31, 2023:(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-MinnesotaElectric generation:Sherco Unit 3$633 $480 59 %Sherco common facilities185 121 80 Sherco substation5 4 59 Electric transmission:Grand Meadow11 4 50 Huntley Wilmarth49 2 50 CapX2020820 141 51 Total NSP-Minnesota (a)$1,703 $752 (a)Projects additionally include $2 million in CWIP.(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent OwnedNSP-WisconsinElectric transmission:La Crosse, WI to Madison, WI$178 $25 37 %CapX2020169 39 80 Total NSP-Wisconsin (a)$347 $64 (a)Projects additionally include $1 million in CWIP." }, { "status": "MODIFIED", "current_title": "Purchased Power and Transmission Services", "prior_title": "Additional Information on Regulatory Authority", "similarity_score": 0.649, "confidence": "medium", "key_changes": [ "Reworded sentence: \"The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.\"", "Reworded sentence: \"PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC.\"", "Reworded sentence: \"The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.\"", "Reworded sentence: \"PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC.\"", "Reworded sentence: \"The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.\"" ], "current_body": "The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost. Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers. 31 31 31 Table of Contents Table of Contents Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill.DSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Pending and Recently Concluded Regulatory ProceedingsColorado Natural Gas Rate Case — In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%). The request was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base. In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:•Use of a historic 2023 test year, with a 13-month average rate base.•Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.•Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to be held in an external trust for future decommissioning costs.•Modifications to recoverability of certain operating expenses.•Denial of PSCo’s decoupling proposal.PSCo placed new rates into effect in November, as modified on ARRR in February 2025, with an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation. The UCA filed a second ARRR in February 2025, which remains pending. Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs. In December 2023, the CPUC approved a framework for two PIMs associated with the generation projects in the portfolio — a PIM related to capital construction costs and another related to ongoing levelized energy costs with details to be further defined via subsequent proceedings throughout 2024. In September 2024, PSCo filed a proposal for implementation of the PIMs. Intervenor testimony is due Feb. 27, 2025, with a final decision expected in summer 2025. In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. In January 2025, the CPUC issued a decision granting limited potential pricing relief, subject to evaluation in future CPCN proceedings for company owned projects. PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and 2025.2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources. •The plan reflects a base sales forecast with 7% compound annual sales growth through 2031. •The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.•The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios. The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio. The table below summarizes two of the proposed portfolios based on the different sales scenarios: Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill.DSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.Electric Commodity AdjustmentRecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. PTCs earned for owned wind generation are returned to customers.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric retail revenues, respectively.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.", "prior_body": "Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market. Pipeline safety compliance. 32 32 32 Table of Contents Table of Contents Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill.DecouplingMechanism 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 AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Pending and Recently Concluded Regulatory ProceedingsColorado 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 OwnedPPAsTotalWind Resources1,325 375 1,700 Solar858 760 1,618 Storage500 1,348 1,848 Natural Gas450 219 669 Total3,133 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 expenses23 Property tax expense10 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. Recovery MechanismsMechanismAdditional InformationColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill.DecouplingMechanism 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 AdjustmentRecovers electric and gas DSM, interruptible service costs and performance incentives for achieving energy savings goals.ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.FCAPSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.Transmission Cost AdjustmentRecovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan.Transportation Electrification PlanRecovers costs associated with the investment in and adoption of transportation electrification infrastructure.Pending and Recently Concluded Regulatory ProceedingsColorado 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." }, { "status": "MODIFIED", "current_title": "Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.", "prior_title": "Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.", "similarity_score": 0.633, "confidence": "medium", "key_changes": [ "Reworded sentence: \"Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance.\"", "Removed sentence: \"Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders.\"", "Removed sentence: \"FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas.\"", "Removed sentence: \"In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties.\"", "Removed sentence: \"Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties.\"" ], "current_body": "Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.", "prior_body": "Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows. Public Policy RisksIncreased risks of regulatory penalties could negatively impact our business.The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows. The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers. In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.Environmental Policy RisksWe may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. International commitments and agreements could result in future additional GHG reductions in the United States. In addition, in 2023 the EPA intends to publish draft regulations for GHG emissions from the power sector consistent with the agency’s Clean Air Act authorities. Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies." }, { "status": "MODIFIED", "current_title": "Annual weather-normalized and leap year adjusted natural gas sales growth (decline)", "prior_title": "Annual weather-normalized natural gas sales growth (decline)", "similarity_score": 0.628, "confidence": "medium", "key_changes": [ "Reworded sentence: \"•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases.\"" ], "current_body": "•Natural gas sales reflect 1.7% residential use per customer and 1.4% C&I use per customer decreases. Partially offsetting these were increased residential and C&I customers in all jurisdictions.", "prior_body": "•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." }, { "status": "MODIFIED", "current_title": "Non-Fuel Operating Expenses and Other Items", "prior_title": "Non-Fuel Operating Expenses and Other Items", "similarity_score": 0.62, "confidence": "medium", "key_changes": [ "Reworded sentence: \"O&M Expenses — O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention.\"", "Reworded sentence: \"and its nonregulated businesses:(Millions of Dollars)20242023Xcel Energy Inc.\"", "Reworded sentence: \"Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment.\"" ], "current_body": "O&M Expenses — O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses. Depreciation and Amortization — Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions. Other Income — Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation. Interest Charges — Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates. AFUDC, Equity and Debt — AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects. Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20242023Xcel Energy Inc. financing costs$(223)$(174)Xcel Energy Inc. taxes and other results (a)38 1 Total Xcel Energy Inc. and other costs$(185)$(173)(Diluted Earnings (Loss) Per Share)20242023Xcel Energy Inc. financing costs$(0.40)$(0.32)Xcel Energy Inc. taxes and other results (a)0.07 0.01 Total Xcel Energy Inc. and other costs$(0.33)$(0.31)(a)Amounts include gain from open market debt repurchases in 2024.Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2023 Comparison with 2022 A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2022 to Dec. 31, 2023 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb. 21, 2024. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.", "prior_body": "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 $102 million in 2023. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20232022Xcel Energy Inc. financing costs$(174)$(153)Venture Holdings (a)3 5 Xcel Energy Inc. taxes and other results(2)(12)Total Xcel Energy Inc. and other costs$(173)$(160)(Diluted Earnings (Loss) Per Share)20232022Xcel Energy Inc. financing costs$(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 RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. 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." }, { "status": "MODIFIED", "current_title": "Purchased Power Arrangements and Transmission Service Providers", "prior_title": "Purchased Power Arrangements and Transmission Service Providers", "similarity_score": 0.598, "confidence": "low", "key_changes": [ "Removed sentence: \"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 GasSPS 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.\"", "Removed sentence: \"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 OperationsSPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products.\"", "Removed sentence: \"SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.\"", "Removed sentence: \"Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.OtherSupply 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.\"", "Removed sentence: \"Manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping.\"" ], "current_body": "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.", "prior_body": "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 GasSPS 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 OperationsSPS 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.OtherSupply 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 TransformersSupply 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 ResourcesIn 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. Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers." }, { "status": "MODIFIED", "current_title": "Pending and Recently Concluded Regulatory Proceedings", "prior_title": "Pending and Recently Concluded Regulatory Proceedings", "similarity_score": 0.595, "confidence": "low", "key_changes": [ "Reworded sentence: \"Colorado Natural Gas Rate Case — In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%).\"", "Reworded sentence: \"In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the GCA rate.\"", "Reworded sentence: \"PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.Wholesale and Commodity Marketing OperationsPSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products.\"", "Reworded sentence: \"(MW)Base PlanLow LoadWind7,250 2,800 Solar3,077 1,200 Natural gas combustion turbine1,575 1,400 Storage (long duration)1,600 — Other storage450 — Total13,952 5,400 The procedural schedule is as follows:•Answer testimony: April 18, 2025•Rebuttal testimony: May 23, 2025•Settlement deadline: June 2, 2025•Hearing: June 10-20, 2025•Statements of position: July 14, 2025A CPUC decision on the resource plan is expected by the fall of 2025 (Phase I) with the competitive solicitation for resource additions expected in early 2026.Wildfire Mitigation Plan — In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC.\"", "Reworded sentence: \"In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the GCA rate.\"" ], "current_body": "2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).", "prior_body": "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 30 30 Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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 JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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 ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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. 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." }, { "status": "MODIFIED", "current_title": "CONSOLIDATED STATEMENTS OF INCOME", "prior_title": "CONSOLIDATED STATEMENTS OF INCOME", "similarity_score": 0.572, "confidence": "low", "key_changes": [ "Reworded sentence: \"31202420232022Operating revenuesElectric$11,147 $11,446 $12,123 Natural gas2,230 2,645 3,080 Other64 115 107 Total operating revenues13,441 14,206 15,310 Operating expensesElectric fuel and purchased power3,788 4,278 5,005 Cost of natural gas sold and transported951 1,456 1,910 Cost of sales — other14 49 44 Operating and maintenance expenses2,540 2,444 2,491 Conservation and demand side management expenses394 286 331 Depreciation and amortization2,744 2,448 2,413 Taxes (other than income taxes)624 657 688 Loss on Comanche Unit 3 litigation— 35 — Workforce reduction expenses— 72 — Total operating expenses11,055 11,725 12,882 Operating income2,386 2,481 2,428 Other income (expense), net143 22 (13)Earnings from equity method investments19 35 36 Allowance for funds used during construction — equity168 91 75 Interest charges and financing costsInterest charges — includes other financing costs1,255 1,055 953 Allowance for funds used during construction — debt(73)(51)(28)Total interest charges and financing costs1,182 1,004 925 Income before income taxes1,534 1,625 1,601 Income tax benefit(402)(146)(135)Net income$1,936 $1,771 $1,736 Weighted average common shares outstanding:Basic563 552 547 Diluted563 552 547 Earnings per average common share:Basic$3.44 $3.21 $3.18 Diluted3.44 3.21 3.17 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents\"" ], "current_body": "(amounts in millions, except per share data) Year Ended Dec. 31202420232022Operating revenuesElectric$11,147 $11,446 $12,123 Natural gas2,230 2,645 3,080 Other64 115 107 Total operating revenues13,441 14,206 15,310 Operating expensesElectric fuel and purchased power3,788 4,278 5,005 Cost of natural gas sold and transported951 1,456 1,910 Cost of sales — other14 49 44 Operating and maintenance expenses2,540 2,444 2,491 Conservation and demand side management expenses394 286 331 Depreciation and amortization2,744 2,448 2,413 Taxes (other than income taxes)624 657 688 Loss on Comanche Unit 3 litigation— 35 — Workforce reduction expenses— 72 — Total operating expenses11,055 11,725 12,882 Operating income2,386 2,481 2,428 Other income (expense), net143 22 (13)Earnings from equity method investments19 35 36 Allowance for funds used during construction — equity168 91 75 Interest charges and financing costsInterest charges — includes other financing costs1,255 1,055 953 Allowance for funds used during construction — debt(73)(51)(28)Total interest charges and financing costs1,182 1,004 925 Income before income taxes1,534 1,625 1,601 Income tax benefit(402)(146)(135)Net income$1,936 $1,771 $1,736 Weighted average common shares outstanding:Basic563 552 547 Diluted563 552 547 Earnings per average common share:Basic$3.44 $3.21 $3.18 Diluted3.44 3.21 3.17 See Notes to Consolidated Financial Statements 48 48 48 Table of Contents Table of Contents", "prior_body": "(amounts in millions, except per share data) Year Ended Dec. 31202320222021Operating revenuesElectric$11,446 $12,123 $11,205 Natural gas2,645 3,080 2,132 Other115 107 94 Total operating revenues14,206 15,310 13,431 Operating expensesElectric fuel and purchased power4,278 5,005 4,733 Cost of natural gas sold and transported1,456 1,910 1,081 Cost of sales — other49 44 38 Operating and maintenance expenses2,444 2,491 2,321 Conservation and demand side management expenses286 331 304 Depreciation and amortization2,448 2,413 2,121 Taxes (other than income taxes)657 688 630 Loss on Comanche Unit 3 litigation35 — — Workforce reduction expenses72 — — Total operating expenses11,725 12,882 11,228 Operating income2,481 2,428 2,203 Other income (expense), net22 (13)5 Earnings from equity method investments35 36 62 Allowance for funds used during construction — equity91 75 73 Interest charges and financing costsInterest charges — includes other financing costs of $32, $31 and $29, respectively1,055 953 842 Allowance for funds used during construction — debt(51)(28)(26)Total interest charges and financing costs1,004 925 816 Income before income taxes1,625 1,601 1,527 Income tax benefit(146)(135)(70)Net income$1,771 $1,736 $1,597 Weighted average common shares outstanding:Basic552 547 539 Diluted552 547 540 Earnings per average common share:Basic$3.21 $3.18 $2.96 Diluted3.21 3.17 2.96 See Notes to Consolidated Financial Statements Interest charges — includes other financing costs of $32, $31 and $29, respectively 47 47 47 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "Pending and Recently Concluded Regulatory Proceedings", "prior_title": "Recently Concluded Regulatory Proceedings", "similarity_score": 0.57, "confidence": "low", "key_changes": [ "Reworded sentence: \"Resource Acquisition — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC.\"", "Reworded sentence: \"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.\"" ], "current_body": "2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).", "prior_body": "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 31 31 Table of Contents 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 SystemPending and Recently Concluded Regulatory Proceedings2022 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 ServicesThe NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance. 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 SystemPending and Recently Concluded Regulatory Proceedings2022 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 ServicesThe NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. 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 $5 million rate increase for the natural gas utility in 2024. The new rates were implemented on Jan. 1, 2024. NSP System" }, { "status": "MODIFIED", "current_title": "Electric Revenues", "prior_title": "Electric Revenues, Fuel and Purchased Power and Electric Margin", "similarity_score": 0.566, "confidence": "low", "key_changes": [ "Reworded sentence: \"Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality.\"", "Reworded sentence: \"and its nonregulated businesses:(Millions of Dollars)20242023Xcel Energy Inc.\"", "Reworded sentence: \"Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment.\"" ], "current_body": "Electric revenues are impacted by changing sales, fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated (wind, nuclear and solar), which reduce electric revenue and income taxes. (Millions of Dollars)2024 vs. 2023Recovery of lower cost of electric fuel and purchase power(479)PTCs flowed back to customers (offset by lower ETR)(302)Wholesale generation revenues(96)Sherco Unit 3 2011 outage refunds(47)Regulatory rate outcomes (MN, CO, TX, and NM)372 Non-fuel riders169 Conservation and demand side management (offset in expense)102 Estimated impact of weather (net of sales true-up)24 Other, net(42)Total decrease$(299) 27 27 27 Table of Contents Table of Contents Natural Gas RevenuesNatural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of natural gas$(496)Estimated impact of weather (net of decoupling)(35)Retail sales decline (net of decoupling)(1)Regulatory rate outcomes (MN, WI, CO, and ND)91 Infrastructure and integrity riders8 Other, net18 Total decrease$(415)Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses decreased $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes.Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.Natural gas sold and transported decreased $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes.Non-Fuel Operating Expenses and Other ItemsO&M Expenses — O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses.Depreciation and Amortization — Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions. Other Income — Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.Interest Charges — Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.AFUDC, Equity and Debt — AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20242023Xcel Energy Inc. financing costs$(223)$(174)Xcel Energy Inc. taxes and other results (a)38 1 Total Xcel Energy Inc. and other costs$(185)$(173)(Diluted Earnings (Loss) Per Share)20242023Xcel Energy Inc. financing costs$(0.40)$(0.32)Xcel Energy Inc. taxes and other results (a)0.07 0.01 Total Xcel Energy Inc. and other costs$(0.33)$(0.31)(a)Amounts include gain from open market debt repurchases in 2024.Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.2023 Comparison with 2022 A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2022 to Dec. 31, 2023 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2023, which was filed with the SEC on Feb. 21, 2024. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. Public Utility RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations and credit quality.See Rate Matters and Other within Note 12 to the consolidated financial statements for further information. Natural Gas RevenuesNatural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.(Millions of Dollars)2024 vs. 2023Recovery of lower cost of natural gas$(496)Estimated impact of weather (net of decoupling)(35)Retail sales decline (net of decoupling)(1)Regulatory rate outcomes (MN, WI, CO, and ND)91 Infrastructure and integrity riders8 Other, net18 Total decrease$(415)Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses decreased $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes.Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.Natural gas sold and transported decreased $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes.Non-Fuel Operating Expenses and Other ItemsO&M Expenses — O&M expenses increased $96 million in 2024 primarily due to operational activities, including generation maintenance, storm response, wildfire mitigation costs and damage prevention. The impact of prior year regulatory deferrals also contributed to increased O&M expenses, partially offset by lower labor and benefit costs and lower bad debt expenses.Depreciation and Amortization — Depreciation and amortization increased $296 million for the year, primarily related to system expansion, partially offset by the impacts of various rate cases, including recognition of previously deferred costs as well as wind and nuclear life extensions. Other Income — Other income increased $121 million for the year, primarily related to interest earned on significant cash balances throughout the year and a gain on debt repurchases, which helped to offset increased spending in our electric and natural gas operations to reduce risk, including wildfire mitigation.Interest Charges — Interest charges increased $200 million in 2024. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.AFUDC, Equity and Debt — AFUDC increased $99 million in 2024. This increase was largely due to increased investment in renewable and transmission projects.", "prior_body": "(Millions of Dollars)20232022Electric revenues$11,446 $12,123 Electric fuel and purchased power(4,278)(5,005)Electric margin$7,168 $7,118 28 28 28 Table of Contents Table of Contents Change in Electric Margin(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)$100 Non-fuel riders89 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 MarginNatural 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)20232022Natural 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. 2022Regulatory 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 ItemsO&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 $102 million in 2023. The increase was largely due to higher long-term debt levels to fund capital investments and higher interest rates.Xcel Energy Inc. and Other ResultsNet income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:(Millions of Dollars)20232022Xcel Energy Inc. financing costs$(174)$(153)Venture Holdings (a)3 5 Xcel Energy Inc. taxes and other results(2)(12)Total Xcel Energy Inc. and other costs$(173)$(160)(Diluted Earnings (Loss) Per Share)20232022Xcel Energy Inc. financing costs$(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 RegulationThe FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas. Change in Electric Margin(Millions of Dollars)2023 vs. 2022Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)$100 Non-fuel riders89 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 MarginNatural 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)20232022Natural 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. 2022Regulatory 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 ItemsO&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." }, { "status": "MODIFIED", "current_title": "Changes in Diluted EPS", "prior_title": "Changes in Diluted EPS", "similarity_score": 0.534, "confidence": "low", "key_changes": [ "Reworded sentence: \"Components significantly contributing to changes in 2024 EPS compared with 2023: Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec.\"" ], "current_body": "Components significantly contributing to changes in 2024 EPS compared with 2023: Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31GAAP diluted EPS — 2023$3.21 Components of change — 2024 vs. 2023Electric regulatory rate outcomes and riders0.73 Higher other income, net0.16 Natural gas regulatory rate outcomes and riders0.14 Workforce reduction expenses 0.09 Loss on Comanche Unit 3 litigation 0.05 Higher depreciation and amortization(0.40)Interest charges, net of AFUDC - debt(0.24)Higher O&M expenses(0.13)Sherco Unit 3 2011 outage refunds(0.06)Other, net(0.11)GAAP diluted EPS — 2024$3.44 Sherco Unit 3 2011 outage refunds0.06 Ongoing diluted EPS — 2024$3.50 ROE for Xcel Energy and its utility subsidiaries: 20242023ROEGAAP ROEOngoing ROEGAAP ROEOngoing ROENSP-Minnesota9.07 %9.46 %8.82 %9.11 %PSCo7.63 7.63 7.32 7.77 SPS9.57 9.57 9.80 9.98 NSP-Wisconsin8.98 8.98 10.38 10.67 Utility Subsidiaries8.55 8.69 8.45 8.79 Xcel Energy10.42 10.61 10.33 10.79", "prior_body": "Components significantly contributing to changes in EPS: 2023 vs. 2022Diluted Earnings (Loss) Per ShareDec. 31GAAP and ongoing diluted EPS — 2022$3.17 Components of change — 2023 vs. 2022Higher electric revenues, net of electric fuel and purchased power0.07 Lower O&M expenses0.06 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 transported0.03 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 expenses0.09 Loss on Comanche Unit 3 litigation0.05 Ongoing diluted EPS — 2023$3.35 ROE for Xcel Energy and its utility subsidiaries: 20232022ROEGAAP ROEOngoing ROEGAAP and Ongoing ROENSP-Minnesota8.82 %9.11 %8.76 %PSCo7.32 7.77 8.23 SPS9.80 9.98 9.36 NSP-Wisconsin10.38 10.67 10.57 Operating Companies8.45 8.79 8.74 Xcel Energy10.33 10.79 10.76" }, { "status": "MODIFIED", "current_title": "Natural Gas Revenues", "prior_title": "Natural Gas Margin", "similarity_score": 0.511, "confidence": "low", "key_changes": [ "Reworded sentence: \"Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.\"" ], "current_body": "Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes. (Millions of Dollars)2024 vs. 2023Recovery of lower cost of natural gas$(496)Estimated impact of weather (net of decoupling)(35)Retail sales decline (net of decoupling)(1)Regulatory rate outcomes (MN, WI, CO, and ND)91 Infrastructure and integrity riders8 Other, net18 Total decrease$(415) Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Electric fuel and purchased power expenses decreased $490 million in 2024. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices, partially offset by increased volumes. Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact. Natural gas sold and transported decreased $505 million in 2024. The decrease is primarily due to lower commodity prices and volumes.", "prior_body": "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." }, { "status": "MODIFIED", "current_title": "CONSOLIDATED BALANCE SHEETS", "prior_title": "CONSOLIDATED BALANCE SHEETS", "similarity_score": 0.506, "confidence": "low", "key_changes": [ "Reworded sentence: \"3120242023AssetsCurrent assetsCash and cash equivalents$179 $129 Accounts receivable, net1,249 1,315 Accrued unbilled revenues832 853 Inventories666 711 Regulatory assets561 611 Derivative instruments114 104 Prepaid taxes72 52 Prepayments and other652 294 Total current assets4,325 4,069 Property, plant and equipment, net57,198 51,642 Other assetsNuclear decommissioning fund and other investments3,896 3,599 Regulatory assets2,849 2,798 Derivative instruments72 76 Operating lease right-of-use assets1,060 1,217 Other635 678 Total other assets8,512 8,368 Total assets$70,035 $64,079 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$1,103 $552 Short-term debt695 785 Accounts payable1,781 1,668 Regulatory liabilities852 528 Taxes accrued535 557 Accrued interest280 251 Dividends payable314 289 Derivative instruments37 74 Operating lease liabilities227 226 Other635 722 Total current liabilities6,459 5,652 Deferred credits and other liabilitiesDeferred income taxes5,319 4,885 Deferred investment tax credits40 60 Regulatory liabilities6,010 5,827 Asset retirement obligations3,713 3,218 Derivative instruments77 86 Customer advances146 167 Pension and employee benefit obligations477 469 Operating lease liabilities867 1,038 Other89 148 Total deferred credits and other liabilities16,738 15,898 Commitments and contingenciesCapitalizationLong-term debt27,316 24,913 Common stock — 1,000,000,000 shares authorized of $2.50 par value; 574,365,598 and 554,941,703 shares outstanding at Dec.\"" ], "current_body": "(amounts in millions, except share and per share) Dec. 3120242023AssetsCurrent assetsCash and cash equivalents$179 $129 Accounts receivable, net1,249 1,315 Accrued unbilled revenues832 853 Inventories666 711 Regulatory assets561 611 Derivative instruments114 104 Prepaid taxes72 52 Prepayments and other652 294 Total current assets4,325 4,069 Property, plant and equipment, net57,198 51,642 Other assetsNuclear decommissioning fund and other investments3,896 3,599 Regulatory assets2,849 2,798 Derivative instruments72 76 Operating lease right-of-use assets1,060 1,217 Other635 678 Total other assets8,512 8,368 Total assets$70,035 $64,079 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$1,103 $552 Short-term debt695 785 Accounts payable1,781 1,668 Regulatory liabilities852 528 Taxes accrued535 557 Accrued interest280 251 Dividends payable314 289 Derivative instruments37 74 Operating lease liabilities227 226 Other635 722 Total current liabilities6,459 5,652 Deferred credits and other liabilitiesDeferred income taxes5,319 4,885 Deferred investment tax credits40 60 Regulatory liabilities6,010 5,827 Asset retirement obligations3,713 3,218 Derivative instruments77 86 Customer advances146 167 Pension and employee benefit obligations477 469 Operating lease liabilities867 1,038 Other89 148 Total deferred credits and other liabilities16,738 15,898 Commitments and contingenciesCapitalizationLong-term debt27,316 24,913 Common stock — 1,000,000,000 shares authorized of $2.50 par value; 574,365,598 and 554,941,703 shares outstanding at Dec. 31, 2024 and Dec. 31, 2023, respectively1,436 1,387 Additional paid in capital9,601 8,465 Retained earnings8,553 7,858 Accumulated other comprehensive loss(68)(94)Total common stockholders’ equity19,522 17,616 Total liabilities and equity$70,035 $64,079 See Notes to Consolidated Financial Statements Common stock — 1,000,000,000 shares authorized of $2.50 par value; 574,365,598 and 554,941,703 shares outstanding at Dec. 31, 2024 and Dec. 31, 2023, respectively 51 51 51 Table of Contents Table of Contents", "prior_body": "(amounts in millions, except share and per share) Dec. 3120232022AssetsCurrent assetsCash and cash equivalents$129 $111 Accounts receivable, net1,315 1,373 Accrued unbilled revenues853 1,105 Inventories711 803 Regulatory assets611 1,059 Derivative instruments104 279 Prepaid taxes52 54 Prepayments and other294 360 Total current assets4,069 5,144 Property, plant and equipment, net51,642 48,253 Other assetsNuclear decommissioning fund and other investments3,599 3,234 Regulatory assets2,798 2,871 Derivative instruments76 93 Operating lease right-of-use assets1,217 1,204 Other678 389 Total other assets8,368 7,791 Total assets$64,079 $61,188 Liabilities and EquityCurrent liabilitiesCurrent portion of long-term debt$552 $1,151 Short-term debt785 813 Accounts payable1,668 1,804 Regulatory liabilities528 418 Taxes accrued557 569 Accrued interest251 217 Dividends payable289 268 Derivative instruments74 76 Operating lease liabilities226 217 Other722 545 Total current liabilities5,652 6,078 Deferred credits and other liabilitiesDeferred income taxes4,885 4,756 Deferred investment tax credits60 48 Regulatory liabilities5,827 5,569 Asset retirement obligations3,218 3,380 Derivative instruments86 113 Customer advances167 181 Pension and employee benefit obligations469 390 Operating lease liabilities1,038 1,038 Other148 147 Total deferred credits and other liabilities15,898 15,622 Commitments and contingenciesCapitalizationLong-term debt24,913 22,813 Common stock — 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively1,387 1,374 Additional paid in capital8,465 8,155 Retained earnings7,858 7,239 Accumulated other comprehensive loss(94)(93)Total common stockholders’ equity17,616 16,675 Total liabilities and equity$64,079 $61,188 See Notes to Consolidated Financial Statements Common stock — 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively 50 50 50 Table of Contents Table of Contents" }, { "status": "MODIFIED", "current_title": "Pending and Recently Concluded Regulatory Proceedings", "prior_title": "Pending and Recently Concluded Regulatory Proceedings", "similarity_score": 0.496, "confidence": "low", "key_changes": [ "Reworded sentence: \"2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%).\"", "Reworded sentence: \"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 GasSPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas.\"", "Reworded sentence: \"Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.OtherSupply Chain Xcel Energy’s ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.\"", "Reworded sentence: \"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 GasSPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas.\"" ], "current_body": "2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%. •ROE of 9.6%. •Equity ratio of 52.5%. •Rate base of $1.25 billion. •No change to Commission approved decoupling. In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025. 2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025. 29 29 29 Table of Contents Table of Contents 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. NSP-Minnesota has notified the NRC of intent to apply for Prairie Island SLR which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.NSP-Wisconsin Summary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.MPSCRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026.2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).Nuclear Power OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism. In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC. 2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025. A decision is expected in 2026. 2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).", "prior_body": "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 30 30 Table of Contents 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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 JurisdictionRegulatory Body / RTOAdditional InformationPSCWRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.Pipeline safety compliance.Michigan Public Service CommissionRetail rates, services and other aspects of electric and natural gas operations.Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.Pipeline safety compliance.FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.DOTPipeline safety compliance.Recovery MechanismsMechanismAdditional InformationAnnual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.Purchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.Wisconsin Energy Efficiency ProgramThe 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 ProceedingsWisconsin 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. 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 OperationsNuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.Low-Level Waste Disposal — Low level waste from Monticello and 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. 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." }, { "status": "MODIFIED", "current_title": "Additional Information", "prior_title": "Additional Information", "similarity_score": 0.489, "confidence": "low", "key_changes": [ "Removed sentence: \"Allows recovery of purchased power capacity costs not included in Texas rates.\"", "Added sentence: \"Pending and Recently Concluded Regulatory Proceedings2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%).\"", "Added sentence: \"Interim rates went into effect on Feb.\"", "Added sentence: \"In April 2024, the PUCT approved a black box settlement between SPS and intervening parties, which reflect the following terms:•A base rate increase of $65 million effective back to July 13, 2023.•A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ allowance for funds used during construction and in other proceedings filed before the PUCT where a stated WACC is required.\"", "Added sentence: \"•The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.•Establishment of a rate rider of approximately $18 million to be recovered over a three-year period for various deferred expenses.\"" ], "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025.", "prior_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP Rider (a)Recovers costs of conservation and DSM programs.Customer Protection MechanismsMISO 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.DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RESRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. Transmission Cost RecoveryRecovers 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 Proceedings2022 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" }, { "status": "MODIFIED", "current_title": "Recently Adopted", "prior_title": "Recently Issued", "similarity_score": 0.489, "confidence": "low", "key_changes": [ "Reworded sentence: \"Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec.\"" ], "current_body": "Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material. See Note 14 for further information.", "prior_body": "Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures" }, { "status": "MODIFIED", "current_title": "Supply Chain", "prior_title": "New Technology and Government Grants", "similarity_score": 0.486, "confidence": "low", "key_changes": [ "Reworded sentence: \"Xcel Energy’s ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.\"", "Reworded sentence: \"31, 2024 and 2023, Xcel Energy had regulatory assets of $3.4 billion and $3.4 billion, respectively and regulatory liabilities of $6.9 billion and $6.4 billion, respectively.\"", "Reworded sentence: \"31, 2024, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets.\"" ], "current_body": "Xcel Energy’s ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain. Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability. In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work. Tariffs and Trade ComplaintsIn May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules. In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. In November 2024, the U.S. Department of Commerce concluded that dumping had occurred and the impact to Xcel Energy is still being evaluated. In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.In January of 2025, the U.S. International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China. This case will be reviewed by the U.S. Department of Commerce and the International Trade Commission over the course of 2025.In early 2025, several executive orders were issued, some of which impose new tariffs on certain imports, which may impact our procurement activities. Xcel Energy continues to assess the impacts of these tariffs, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs. In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work. Tariffs and Trade Complaints In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules. In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. In November 2024, the U.S. Department of Commerce concluded that dumping had occurred and the impact to Xcel Energy is still being evaluated. In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications. In January of 2025, the U.S. International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China. This case will be reviewed by the U.S. Department of Commerce and the International Trade Commission over the course of 2025. In early 2025, several executive orders were issued, some of which impose new tariffs on certain imports, which may impact our procurement activities. Xcel Energy continues to assess the impacts of these tariffs, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions. Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs. 35 35 35 Table of Contents Table of Contents Excess Liability Insurance CoverageXcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states. Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 2024 and 2023, Xcel Energy had regulatory assets of $3.4 billion and $3.4 billion, respectively and regulatory liabilities of $6.9 billion and $6.4 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. At Dec. 31, 2024, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets. See Notes 4 and 12 to the consolidated financial statements for further information.Income Tax AccrualsJudgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings. See Note 7 to the consolidated financial statements for further information.Employee BenefitsWe sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed. Excess Liability Insurance CoverageXcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy received an approved deferral at PSCo, filed a deferral request at NSP-Wisconsin and will continue to seek to recover these increased costs through various regulatory proceedings, including planned deferral requests or rate filings in several states. Critical Accounting Policies and EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.", "prior_body": "Hydrogen Hub Grant In October 2023, the 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 EstimatesPreparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported. Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.Regulatory AccountingXcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.As of Dec. 31, 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." }, { "status": "MODIFIED", "current_title": "Additional Information on Regulatory Authority", "prior_title": "Purchased Power and Transmission Services", "similarity_score": 0.479, "confidence": "low", "key_changes": [ "Reworded sentence: \"Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.\"" ], "current_body": "Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market. Pipeline safety compliance.", "prior_body": "The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements. Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.Wholesale and Commodity Marketing OperationsNSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates. PSCoSummary of Regulatory Agencies / RTO and Areas of JurisdictionRegulatory Body / RTOAdditional Information on Regulatory AuthorityCPUCRetail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.Reviews and approves Integrated Resource Plans for meeting future energy needs.Certifies the need and siting for generating plans greater than 50 MW.Pipeline safety compliance.FERCWholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.RTOPSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market.DOTPipeline safety compliance. 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." }, { "status": "MODIFIED", "current_title": "Operating Cash Flows", "prior_title": "Operating Cash Flows", "similarity_score": 0.474, "confidence": "low", "key_changes": [ "Reworded sentence: \"31Cash provided by operating activities — 2023$5,327 Components of change — 2024 vs.\"" ], "current_body": "(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities — 2023$5,327 Components of change — 2024 vs. 2023Higher net income165 Non-cash transactions222 Changes in deferred taxes284 Changes in working capital (783)Changes in net regulatory and other assets and liabilities(574)Cash provided by operating activities — 2024$4,641 Net cash provided by operating activities decreased by $686 million for 2024 as compared to 2023. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers. Investing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash used in investing activities — 2023$(5,926)Components of change — 2024 vs. 2023Increased capital expenditures(1,510)Other investing activities8 Cash used in investing activities — 2024$(7,428)Net cash used in investing activities increased by $1,502 million for 2024 as compared to 2023. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.Financing Cash Flows(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by financing activities —2023$617 Components of change — 2024 vs. 2023Higher long-term debt issuances, net of repayments1,512 Higher proceeds from issuance of common stock847 Higher dividends paid to shareholders(83)Other financing activities(56)Cash provided by financing activities — 2024$2,837 Net cash provided by financing activities increased by $2,220 million for 2024 as compared to 2023. The increase was largely related to additional debt and common stock issuances to fund capital investment.See Note 5 to the consolidated financial statements for further information.Capital RequirementsXcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation.", "prior_body": "(Millions of Dollars)Twelve Months Ended Dec. 31Cash provided by operating activities — 2022$3,932 Components of change — 2023 vs. 2022Higher net income35 Non-cash transactions88 Changes in working capital900 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." }, { "status": "UNCHANGED", "current_title": "Recovery Mechanisms", "prior_title": "Recovery Mechanisms", "current_body": "MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization." }, { "status": "UNCHANGED", "current_title": "We are subject to capital market and interest rate risks.", "prior_title": "We are subject to capital market and interest rate risks.", "current_body": "Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates." }, { "status": "UNCHANGED", "current_title": "The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.", "prior_title": "The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.", "current_body": "In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service." }, { "status": "UNCHANGED", "current_title": "Additional Information", "prior_title": "Additional Information", "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025." }, { "status": "UNCHANGED", "current_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "prior_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "current_body": "Regulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance." }, { "status": "UNCHANGED", "current_title": "Increasing costs associated with health care plans may adversely affect our results of operations.", "prior_title": "Increasing costs associated with health care plans may adversely affect our results of operations.", "current_body": "Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs." }, { "status": "UNCHANGED", "current_title": "Wholesale and Commodity Marketing Operations", "prior_title": "Wholesale and Commodity Marketing Operations", "current_body": "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" }, { "status": "UNCHANGED", "current_title": "Additional Information", "prior_title": "Additional Information", "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025." }, { "status": "UNCHANGED", "current_title": "Wholesale and Commodity Marketing Operations", "prior_title": "Wholesale and Commodity Marketing Operations", "current_body": "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" }, { "status": "UNCHANGED", "current_title": "Increased risks of regulatory penalties could negatively impact our business.", "prior_title": "Increased risks of regulatory penalties could negatively impact our business.", "current_body": "The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows." }, { "status": "UNCHANGED", "current_title": "REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM", "prior_title": "REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM", "current_body": "To the stockholders and the Board of Directors of Xcel Energy Inc." }, { "status": "UNCHANGED", "current_title": "Fair Value Measurements", "prior_title": "Fair Value Measurements", "current_body": "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." }, { "status": "UNCHANGED", "current_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "prior_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "current_body": "Regulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance." }, { "status": "UNCHANGED", "current_title": "Ongoing ROE", "prior_title": "Ongoing ROE", "current_body": "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." }, { "status": "UNCHANGED", "current_title": "Critical Accounting Policies and Estimates", "prior_title": "Critical Accounting Policies and Estimates", "current_body": "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." }, { "status": "UNCHANGED", "current_title": "Non-GAAP Financial Measures", "prior_title": "Non-GAAP Financial Measures", "current_body": "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." }, { "status": "UNCHANGED", "current_title": "Failure to attract and retain a qualified workforce could have an adverse effect on operations.", "prior_title": "Failure to attract and retain a qualified workforce could have an adverse effect on operations.", "current_body": "The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows. Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows. National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs." }, { "status": "UNCHANGED", "current_title": "Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.", "prior_title": "Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.", "current_body": "Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows." }, { "status": "UNCHANGED", "current_title": "Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.", "prior_title": "Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.", "current_body": "We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs." }, { "status": "UNCHANGED", "current_title": "Basis for Opinions", "prior_title": "Basis for Opinions", "current_body": "The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions." }, { "status": "UNCHANGED", "current_title": "Income Tax Accruals", "prior_title": "Income Tax Accruals", "current_body": "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." }, { "status": "UNCHANGED", "current_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "prior_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "current_body": "Regulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance." }, { "status": "UNCHANGED", "current_title": "Operations could be impacted by war, terrorism or other events.", "prior_title": "Operations could be impacted by war, terrorism or other events.", "current_body": "Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility. We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption. In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows." }, { "status": "UNCHANGED", "current_title": "Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.", "prior_title": "Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.", "current_body": "We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance and safety standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines." }, { "status": "UNCHANGED", "current_title": "Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.", "prior_title": "Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.", "current_body": "NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include: •Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal. •Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor. •Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change. The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses. If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs." }, { "status": "UNCHANGED", "current_title": "Purchases of Equity Securities by Issuer and Affiliated Purchasers", "prior_title": "Purchases of Equity Securities by Issuer and Affiliated Purchasers", "current_body": "For the quarter ended Dec. 31, 2024, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 — [RESERVED] ITEM 6 — [RESERVED] ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" }, { "status": "UNCHANGED", "current_title": "Credit Facility (a)", "prior_title": "Credit Facility (a)", "current_body": "Drawn (b) (a)These credit facilities mature in September 2027. These credit facilities mature in September 2027. (b)Includes outstanding commercial paper and letters of credit. Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023." }, { "status": "UNCHANGED", "current_title": "Comprehensive Loss", "prior_title": "Comprehensive Loss", "current_body": "Dividends declared on common stock ($1.95 per share) Dividends declared on common stock ($2.08 per share) Dividends declared on common stock ($2.19 per share) 52 52 52 Table of Contents Table of Contents XCEL ENERGY INC. AND SUBSIDIARIESNotes to Consolidated Financial Statements1. Summary of Significant Accounting PoliciesGeneral — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.Xcel Energy Inc.’s nonregulated subsidiaries include:Nonregulated SubsidiaryPurposeEloigneInvests in rental housing projects that qualify for low-income housing tax credits.Capital ServicesProcures equipment for construction of renewable generation facilities at other subsidiaries.Xcel Energy Venture Holdings, Inc.Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.Nicollet Project HoldingsInvests in nonregulated assets such as the Minnesota community solar gardens.Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:Direct SubsidiaryXcel Energy Wholesale Group Inc.Xcel Energy Markets Holdings Inc.Xcel Energy Ventures Inc.Xcel Energy Retail Holdings Inc.Xcel Energy Communication Group Inc.Xcel Energy International Inc.Xcel Energy Transmission Holding Company, LLCNicollet Holdings Company, LLCXcel Energy Nuclear Services Holdings, LLCXcel Energy Services Inc.Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. The equity method of accounting is used for its investments in energy technology funds and WYCO.Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income.The consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts.Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.Xcel Energy has evaluated events occurring after Dec. 31, 2024 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.Use of Estimates — Xcel Energy uses estimates based on the best information available to record transactions and balances resulting from business operations. Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations, actuarially determined benefit costs and wildfire contingencies. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.Regulatory Accounting — The regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows. See Note 4 for further information.Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected. XCEL ENERGY INC. AND SUBSIDIARIESNotes to Consolidated Financial Statements1. Summary of Significant Accounting PoliciesGeneral — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.Xcel Energy Inc.’s nonregulated subsidiaries include:Nonregulated SubsidiaryPurposeEloigneInvests in rental housing projects that qualify for low-income housing tax credits.Capital ServicesProcures equipment for construction of renewable generation facilities at other subsidiaries.Xcel Energy Venture Holdings, Inc.Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.Nicollet Project HoldingsInvests in nonregulated assets such as the Minnesota community solar gardens.Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:Direct SubsidiaryXcel Energy Wholesale Group Inc.Xcel Energy Markets Holdings Inc.Xcel Energy Ventures Inc.Xcel Energy Retail Holdings Inc.Xcel Energy Communication Group Inc.Xcel Energy International Inc.Xcel Energy Transmission Holding Company, LLCNicollet Holdings Company, LLCXcel Energy Nuclear Services Holdings, LLCXcel Energy Services Inc.Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. The equity method of accounting is used for its investments in energy technology funds and WYCO.Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income.The consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts.Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows." }, { "status": "UNCHANGED", "current_title": "Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements.", "prior_title": "Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements.", "current_body": "Critical Audit Matter Description The Company 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. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes. The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations 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. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result 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. We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and requirements to refund amounts to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: •We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates. •We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments. •We read relevant regulatory orders issued by the Commissions for the Company, other regulatory filings, legal decisions and recommendations being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We compared the regulatory orders, filings and other publicly available information to the Company’s recorded regulatory assets and liabilities for completeness. •We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates. 46 46 46 Table of Contents Table of Contents" }, { "status": "UNCHANGED", "current_title": "Definition and Limitations of Internal Control over Financial Reporting", "prior_title": "Definition and Limitations of Internal Control over Financial Reporting", "current_body": "A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 45 45 45 Table of Contents Table of Contents" }, { "status": "UNCHANGED", "current_title": "Oversight of Risk and Related Processes", "prior_title": "Oversight of Risk and Related Processes", "current_body": "The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors. Xcel Energy maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our Code of Conduct and compliance policies, operation of formal risk management structures and overall business management. Xcel Energy further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal. Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls. Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing Xcel Energy’s strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals. Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental, safety and security risks. The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of Xcel Energy. The Board of Directors assigns oversight of critical risks to each of its four committees to confirm these risks are well understood and given appropriate focus. The Audit Committee is responsible for reviewing the adequacy of the committees’ risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate.Emerging risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed.Risks Associated with Our BusinessOperational RisksOur natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential reputational impact.Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to:•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. •Failures in the availability, acquisition or transportation of fuel or other supplies. •Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns•Performance below expected or contracted levels of output or efficiency.•Availability of replacement or new equipment. •Availability of adequate water resources and ability to satisfy water intake and discharge requirements. •Inability to identify, manage properly or mitigate equipment defects. •Use of new or unproven technology. •Inability to use information effectively given the rapidly increasing volume of data.•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes. •Increased costs due to aging infrastructure. The Audit Committee is responsible for reviewing the adequacy of the committees’ risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate. Emerging risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed." }, { "status": "UNCHANGED", "current_title": "1. Summary of Significant Accounting Policies", "prior_title": "1. Summary of Significant Accounting Policies", "current_body": "General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas. Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc.’s nonregulated subsidiaries include:Nonregulated SubsidiaryPurposeEloigneInvests in rental housing projects that qualify for low-income housing tax credits.Capital ServicesProcures equipment for construction of renewable generation facilities at other subsidiaries.Xcel Energy Venture Holdings, Inc.Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.Nicollet Project HoldingsInvests in nonregulated assets such as the Minnesota community solar gardens. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:Direct SubsidiaryXcel Energy Wholesale Group Inc.Xcel Energy Markets Holdings Inc.Xcel Energy Ventures Inc.Xcel Energy Retail Holdings Inc.Xcel Energy Communication Group Inc.Xcel Energy International Inc.Xcel Energy Transmission Holding Company, LLCNicollet Holdings Company, LLCXcel Energy Nuclear Services Holdings, LLCXcel Energy Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy. Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. The equity method of accounting is used for its investments in energy technology funds and WYCO. Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income. The consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows. Xcel Energy has evaluated events occurring after Dec. 31, 2024 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.Use of Estimates — Xcel Energy uses estimates based on the best information available to record transactions and balances resulting from business operations. Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations, actuarially determined benefit costs and wildfire contingencies. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.Regulatory Accounting — The regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows. See Note 4 for further information.Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected. Xcel Energy has evaluated events occurring after Dec. 31, 2024 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. Use of Estimates — Xcel Energy uses estimates based on the best information available to record transactions and balances resulting from business operations. Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations, actuarially determined benefit costs and wildfire contingencies. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results. Regulatory Accounting — The regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: •Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates. •Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows. See Note 4 for further information. Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected. 53 53 53 Table of Contents Table of Contents Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740, Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms.Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.Interest and penalties related to income taxes are reported within Other income (expense), net or interest charges in the consolidated statements of income.Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.See Note 7 for further information.Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs and replacement of items determined to be less than a unit of property are charged to expense as incurred.Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.8% for 2024, 3.6% for 2023 and 3.7% for 2022.See Note 3 for further information.AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.See Note 12 for further information.Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval. The latest decommissioning study was deferred one year and completed in 2024.NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.Restricted funds for future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Notes 10 and 12 for further information.Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 11 for further information. Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740, Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms.Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.Interest and penalties related to income taxes are reported within Other income (expense), net or interest charges in the consolidated statements of income.Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.See Note 7 for further information.Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs and replacement of items determined to be less than a unit of property are charged to expense as incurred.Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740, Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms. Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense. Interest and penalties related to income taxes are reported within Other income (expense), net or interest charges in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information. Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs and replacement of items determined to be less than a unit of property are charged to expense as incurred. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.8% for 2024, 3.6% for 2023 and 3.7% for 2022.See Note 3 for further information.AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.See Note 12 for further information.Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval. The latest decommissioning study was deferred one year and completed in 2024.NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.Restricted funds for future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Notes 10 and 12 for further information.Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 11 for further information. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.8% for 2024, 3.6% for 2023 and 3.7% for 2022. See Note 3 for further information. AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. See Note 12 for further information. Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval. The latest decommissioning study was deferred one year and completed in 2024. three NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. Restricted funds for future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Notes 10 and 12 for further information. Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 11 for further information. 54 54 54 Table of Contents Table of Contents Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Estimated future expenditures to restore sites are generally treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.See Note 12 for further information.Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO are recorded on a net basis in cost of sales.See Note 6 for further information.Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2024 and 2023, the allowance for bad debts was $111 million and $128 million, respectively. Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following: (Millions of Dollars)Dec. 31, 2024Dec. 31, 2023InventoriesMaterials and supplies$406 $377 Fuel164 211 Natural gas96 123 Total inventories$666 $711 Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and energy technology funds, which requires Xcel Energy’s recognition of its share of these investees’ results, based on Xcel Energy’s proportional ownership interest. For investments in energy technology funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies. Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security. See Notes 10 and 11 for further information.Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use and sale in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.See Note 10 for further information. Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Estimated future expenditures to restore sites are generally treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.See Note 12 for further information.Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO are recorded on a net basis in cost of sales.See Note 6 for further information.Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2024 and 2023, the allowance for bad debts was $111 million and $128 million, respectively. Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Estimated future expenditures to restore sites are generally treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied. See Note 12 for further information. Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO are recorded on a net basis in cost of sales. See Note 6 for further information. Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. three Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2024 and 2023, the allowance for bad debts was $111 million and $128 million, respectively. Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following: (Millions of Dollars)Dec. 31, 2024Dec. 31, 2023InventoriesMaterials and supplies$406 $377 Fuel164 211 Natural gas96 123 Total inventories$666 $711 Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and energy technology funds, which requires Xcel Energy’s recognition of its share of these investees’ results, based on Xcel Energy’s proportional ownership interest. For investments in energy technology funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies. Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security. See Notes 10 and 11 for further information.Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use and sale in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.See Note 10 for further information. Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following: (Millions of Dollars)Dec. 31, 2024Dec. 31, 2023InventoriesMaterials and supplies$406 $377 Fuel164 211 Natural gas96 123 Total inventories$666 $711 Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and energy technology funds, which requires Xcel Energy’s recognition of its share of these investees’ results, based on Xcel Energy’s proportional ownership interest. For investments in energy technology funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies. Equity Method Investments — Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value. For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security. See Notes 10 and 11 for further information. Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use and sale in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales. See Note 10 for further information. 55 55 55 Table of Contents Table of Contents Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.Commodity trading activities are not associated with energy produced from generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further information.Other Utility ItemsAFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base. Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.2. Accounting PronouncementsRecently AdoptedSegment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material.See Note 14 for further information. Recently IssuedIncome Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements. Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements.Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disaggregated disclosure of income statement expenses for public business entities. The ASU is effective for annual periods beginning after Dec. 15, 2026. Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.Commodity trading activities are not associated with energy produced from generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further information.Other Utility ItemsAFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base. Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income. Commodity trading activities are not associated with energy produced from generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 for further information." }, { "status": "UNCHANGED", "current_title": "Additional Information", "prior_title": "Additional Information", "current_body": "Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. Pipeline safety compliance. Pipeline safety compliance. Recovery MechanismsMechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. Pending and Recently Concluded Regulatory Proceedings2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms: •Natural gas rate increase of $46 million, or 7.5%.•ROE of 9.6%.•Equity ratio of 52.5%.•Rate base of $1.25 billion.•No change to Commission approved decoupling.In October 2024, an ALJ recommended the MPUC approve the rate case settlement. In February 2025, the MPUC verbally approved the settlement agreement. NSP-Minnesota expects to implement a rate increase of $50 million (trued up for 2024 weather normalized actual sales) in July 2025.2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In November 2024, the NDPSC approved a settlement, reflecting a natural gas rate increase of $7.2 million (8.0%), based on a ROE of 9.9% and an equity ratio of 52.5%. Rates were implemented on Jan. 1, 2025." }, { "status": "UNCHANGED", "current_title": "Management Report on Internal Control Over Financial Reporting", "prior_title": "Management Report on Internal Control Over Financial Reporting", "current_body": "The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2024. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2024, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria. Xcel Energy Inc.’s independent registered public accounting firm has issued an attestation report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein. /s/ ROBERT C. FRENZEL/s/ BRIAN J. VAN ABELRobert C. FrenzelBrian J. Van AbelChairman, President, Chief Executive Officer and DirectorExecutive Vice President, Chief Financial OfficerFeb. 27, 2025Feb. 27, 2025 44 44 44 Table of Contents Table of Contents" }, { "status": "UNCHANGED", "current_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "prior_title": "Summary of Regulatory Agencies / RTO and Areas of Jurisdiction", "current_body": "Regulatory Body / RTOAdditional InformationMPUCRetail 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.NDPSCRetail 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.SDPUCRetail 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.FERCWholesale 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.MISONSP-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.DOTPipeline safety compliance.Minnesota Office of Pipeline SafetyPipeline safety compliance." }, { "status": "UNCHANGED", "current_title": "Federal tax law may significantly impact our business.", "prior_title": "Federal tax law may significantly impact our business.", "current_body": "Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources." }, { "status": "UNCHANGED", "current_title": "Economic conditions impact our business.", "prior_title": "Economic conditions impact our business.", "current_body": "Xcel Energy’s operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense. Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates. The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand." }, { "status": "UNCHANGED", "current_title": "Comparison of Five Year Cumulative Total Return*", "prior_title": "Comparison of Five Year Cumulative Total Return*", "current_body": "* $100 invested on Dec. 31, 2019 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31. 24 24 24 Table of Contents Table of Contents Purchases of Equity Securities by Issuer and Affiliated PurchasersFor the quarter ended Dec. 31, 2024, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 — [RESERVED]ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSNon-GAAP Financial MeasuresThe 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 ROEOngoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP. The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:(Millions of Dollars)20242023GAAP net income$1,936 $1,771 Loss on Comanche Unit 3 litigation— 35 Workforce reduction expenses— 72 Sherco Unit 3 2011 outage refunds47 — Less: tax effect of adjustments(13)(27)Ongoing earnings (a)$1,969 $1,851 (a)Amounts may not add due to rounding.Twelve Months Ended Dec. 31, 2024Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.41 $0.06 $1.47 PSCo1.39 — 1.39 SPS0.70 — 0.70 NSP-Wisconsin0.24 — 0.24 Earnings from equity method investments — WYCO0.03 — 0.03 Regulated utility (a)3.76 0.06 3.83 Xcel Energy Inc. and Other(0.33)— (0.33)Total (a)$3.44 0.06 $3.50 Twelve Months Ended Dec. 31, 2023Diluted Earnings (Loss) Per ShareGAAP Diluted EPSImpact of AdjustmentsOngoing Diluted EPSNSP-Minnesota$1.28 $0.04 $1.32 PSCo (a)1.26 0.08 1.33 SPS0.70 0.01 0.71 NSP-Wisconsin0.25 — 0.25 Earnings from equity method investments — WYCO0.04 — 0.04 Regulated utility (a)3.52 0.14 3.66 Xcel Energy Inc. and Other(0.31)— (0.31)Total (a)$3.21 0.14 $3.35 (a)Amounts may not add due to rounding.Adjustments to GAAP net income include:Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In 2024, following contested case procedures, Xcel Energy recognized a customer refund of $47 million for replacement power incurred during the outage. Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo recognized a non-recurring $34 million charge as a result of a jury verdict in Denver County District Court awarding CORE Electric Cooperative lost power damages and other costs.Workforce Reduction — In 2023, Xcel Energy implemented workforce actions to align resources and investments with our evolving business and customer needs and streamline the organization for long-term success. Xcel Energy initiated a Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired. Xcel Energy also eliminated approximately 150 non-bargaining employees through an involuntary severance program. Workforce reduction expenses of $72 million were recorded in the fourth quarter of 2023. Purchases of Equity Securities by Issuer and Affiliated PurchasersFor the quarter ended Dec. 31, 2024, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers. ITEM 6 — [RESERVED]ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSNon-GAAP Financial MeasuresThe 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 ROEOngoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP." }, { "status": "UNCHANGED", "current_title": "Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.", "prior_title": "Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.", "current_body": "Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings." }, { "status": "UNCHANGED", "current_title": "Capital Requirements", "prior_title": "Capital Requirements", "current_body": "Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation. 40 40 40 Table of Contents Table of Contents" }, { "status": "UNCHANGED", "current_title": "Long-Term Borrowings and Other Financing Instruments", "prior_title": "Long-Term Borrowings and Other Financing Instruments", "current_body": "Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance. 59 59 59 Table of Contents Table of Contents Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20242023Unsecured senior notes3.30 %June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes4.60 June 1, 2032700 700 Unsecured senior notes (a)5.45 Aug. 15, 2033800 800 Unsecured senior notes (b)5.50 March 15, 2034800 — Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(9)(8)Unamortized debt issuance cost(34)(36)Current maturities (600)— Total long-term debt$6,337 $6,136 (a)2023 financing.(b)2024 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds7.125 %July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds4.50 June 1, 2052500 500 First mortgage bonds (a)5.10 May 15, 2053800 800 First mortgage bonds (b)5.40 March 15, 2054700 — Other long-term debt2 2 Long-term debt — related parties principal amount outstanding2.60 Jun 1, 2051(166)— Unamortized discount(49)(49)Unamortized debt issuance cost(80)(73)Current maturities(250)— Total long-term debt$7,607 $7,330 (a)2023 financing.(b)2024 financing. NSP-WisconsinFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds3.30 %June 15, 2024$— $100 First mortgage bonds3.30 June 15, 2024— 100 First mortgage bonds6.375 Sept. 1, 2038200 200 First mortgage bonds3.70 Oct. 1, 2042100 100 First mortgage bonds3.75 Dec. 1, 2047100 100 First mortgage bonds4.20 Sept. 1, 2048200 200 First mortgage bonds 3.05 May 1, 2051100 100 First mortgage bonds2.82 May 1, 2051100 100 First mortgage bonds4.86 Sept. 15, 2052100 100 First mortgage bonds (a)5.30 June 15, 2053125 125 First mortgage bonds (b)5.65 June 15, 2054400 — Unamortized discount(4)(3)Unamortized debt issuance cost(15)(11)Current maturities— (200)Total long-term debt$1,406 $1,011 (a)2023 financing. (b)2024 financing.PSCoFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds2.90 %May 15, 2025250 250 First mortgage bonds3.70 June 15, 2028350 350 First mortgage bonds1.90 Jan. 15, 2031375 375 First mortgage bonds 1.875 June 15, 2031750 750 First mortgage bonds4.10 June 1, 2032300 300 First mortgage bonds (a)5.35 May 15, 2034450 — First mortgage bonds6.25 Sept. 1, 2037350 350 First mortgage bonds6.50 Aug. 1, 2038300 300 First mortgage bonds4.75 Aug. 15, 2041250 250 First mortgage bonds3.60 Sept. 15, 2042500 500 First mortgage bonds3.95 March 15, 2043250 250 First mortgage bonds4.30 March 15, 2044300 300 First mortgage bonds3.55 June 15, 2046250 250 First mortgage bonds3.80 June 15, 2047400 400 First mortgage bonds4.10 June 15, 2048350 350 First mortgage bonds4.05 Sept. 15, 2049400 400 First mortgage bonds3.20 March 1, 2050550 550 First mortgage bonds2.70 Jan. 15, 2051375 375 First mortgage bonds4.50 June 1, 2052400 400 First mortgage bonds (b)5.25 April 1, 2053850 850 First mortgage bonds (a)5.75 May 15, 2054750 — Unamortized discount(42)(41)Unamortized debt issuance cost(67)(59)Current maturities(250)— Total long-term debt$8,391 $7,450 (a)2024 financing.(b)2023 financing. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates):Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20242023Unsecured senior notes3.30 %June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes4.60 June 1, 2032700 700 Unsecured senior notes (a)5.45 Aug. 15, 2033800 800 Unsecured senior notes (b)5.50 March 15, 2034800 — Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(9)(8)Unamortized debt issuance cost(34)(36)Current maturities (600)— Total long-term debt$6,337 $6,136 (a)2023 financing.(b)2024 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds7.125 %July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds4.50 June 1, 2052500 500 First mortgage bonds (a)5.10 May 15, 2053800 800 First mortgage bonds (b)5.40 March 15, 2054700 — Other long-term debt2 2 Long-term debt — related parties principal amount outstanding2.60 Jun 1, 2051(166)— Unamortized discount(49)(49)Unamortized debt issuance cost(80)(73)Current maturities(250)— Total long-term debt$7,607 $7,330 (a)2023 financing.(b)2024 financing. Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates): Xcel Energy Inc.Financing InstrumentInterest RateMaturity Date20242023Unsecured senior notes3.30 %June 1, 2025250 250 Unsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes1.75 March 15, 2027500 500 Unsecured senior notes4.00 June 15, 2028130 130 Unsecured senior notes 4.00 June 15, 2028500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 Unsecured senior notes 3.40 June 1, 2030600 600 Unsecured senior notes 2.35 Nov. 15, 2031300 300 Unsecured senior notes4.60 June 1, 2032700 700 Unsecured senior notes (a)5.45 Aug. 15, 2033800 800 Unsecured senior notes (b)5.50 March 15, 2034800 — Unsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes3.50 Dec. 1, 2049500 500 Unamortized discount(9)(8)Unamortized debt issuance cost(34)(36)Current maturities (600)— Total long-term debt$6,337 $6,136 Unsecured senior notes Unsecured senior notes (a) Unsecured senior notes (b) (a)2023 financing. (b)2024 financing. NSP-MinnesotaFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds7.125 %July 1, 2025250 250 First mortgage bonds6.50 March 1, 2028150 150 First mortgage bonds2.25 April 1, 2031425 425 First mortgage bonds5.25 July 15, 2035250 250 First mortgage bonds 6.25 June 1, 2036400 400 First mortgage bonds6.20 July 1, 2037350 350 First mortgage bonds5.35 Nov. 1, 2039300 300 First mortgage bonds4.85 Aug. 15, 2040250 250 First mortgage bonds3.40 Aug. 15, 2042500 500 First mortgage bonds4.125 May 15, 2044300 300 First mortgage bonds4.00 Aug. 15, 2045300 300 First mortgage bonds3.60 May 15, 2046350 350 First mortgage bonds3.60 Sept. 15, 2047600 600 First mortgage bonds2.90 March 1, 2050600 600 First mortgage bonds2.60 June 1, 2051700 700 First mortgage bonds3.20 April 1, 2052425 425 First mortgage bonds4.50 June 1, 2052500 500 First mortgage bonds (a)5.10 May 15, 2053800 800 First mortgage bonds (b)5.40 March 15, 2054700 — Other long-term debt2 2 Long-term debt — related parties principal amount outstanding2.60 Jun 1, 2051(166)— Unamortized discount(49)(49)Unamortized debt issuance cost(80)(73)Current maturities(250)— Total long-term debt$7,607 $7,330 First mortgage bonds (a) First mortgage bonds (b) (a)2023 financing. 2023 financing. (b)2024 financing. NSP-WisconsinFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds3.30 %June 15, 2024$— $100 First mortgage bonds3.30 June 15, 2024— 100 First mortgage bonds6.375 Sept. 1, 2038200 200 First mortgage bonds3.70 Oct. 1, 2042100 100 First mortgage bonds3.75 Dec. 1, 2047100 100 First mortgage bonds4.20 Sept. 1, 2048200 200 First mortgage bonds 3.05 May 1, 2051100 100 First mortgage bonds2.82 May 1, 2051100 100 First mortgage bonds4.86 Sept. 15, 2052100 100 First mortgage bonds (a)5.30 June 15, 2053125 125 First mortgage bonds (b)5.65 June 15, 2054400 — Unamortized discount(4)(3)Unamortized debt issuance cost(15)(11)Current maturities— (200)Total long-term debt$1,406 $1,011 (a)2023 financing. (b)2024 financing.PSCoFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds2.90 %May 15, 2025250 250 First mortgage bonds3.70 June 15, 2028350 350 First mortgage bonds1.90 Jan. 15, 2031375 375 First mortgage bonds 1.875 June 15, 2031750 750 First mortgage bonds4.10 June 1, 2032300 300 First mortgage bonds (a)5.35 May 15, 2034450 — First mortgage bonds6.25 Sept. 1, 2037350 350 First mortgage bonds6.50 Aug. 1, 2038300 300 First mortgage bonds4.75 Aug. 15, 2041250 250 First mortgage bonds3.60 Sept. 15, 2042500 500 First mortgage bonds3.95 March 15, 2043250 250 First mortgage bonds4.30 March 15, 2044300 300 First mortgage bonds3.55 June 15, 2046250 250 First mortgage bonds3.80 June 15, 2047400 400 First mortgage bonds4.10 June 15, 2048350 350 First mortgage bonds4.05 Sept. 15, 2049400 400 First mortgage bonds3.20 March 1, 2050550 550 First mortgage bonds2.70 Jan. 15, 2051375 375 First mortgage bonds4.50 June 1, 2052400 400 First mortgage bonds (b)5.25 April 1, 2053850 850 First mortgage bonds (a)5.75 May 15, 2054750 — Unamortized discount(42)(41)Unamortized debt issuance cost(67)(59)Current maturities(250)— Total long-term debt$8,391 $7,450 (a)2024 financing.(b)2023 financing. NSP-WisconsinFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds3.30 %June 15, 2024$— $100 First mortgage bonds3.30 June 15, 2024— 100 First mortgage bonds6.375 Sept. 1, 2038200 200 First mortgage bonds3.70 Oct. 1, 2042100 100 First mortgage bonds3.75 Dec. 1, 2047100 100 First mortgage bonds4.20 Sept. 1, 2048200 200 First mortgage bonds 3.05 May 1, 2051100 100 First mortgage bonds2.82 May 1, 2051100 100 First mortgage bonds4.86 Sept. 15, 2052100 100 First mortgage bonds (a)5.30 June 15, 2053125 125 First mortgage bonds (b)5.65 June 15, 2054400 — Unamortized discount(4)(3)Unamortized debt issuance cost(15)(11)Current maturities— (200)Total long-term debt$1,406 $1,011 First mortgage bonds (a) First mortgage bonds (b) (a)2023 financing. 2023 financing. (b)2024 financing. 2024 financing. PSCoFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds2.90 %May 15, 2025250 250 First mortgage bonds3.70 June 15, 2028350 350 First mortgage bonds1.90 Jan. 15, 2031375 375 First mortgage bonds 1.875 June 15, 2031750 750 First mortgage bonds4.10 June 1, 2032300 300 First mortgage bonds (a)5.35 May 15, 2034450 — First mortgage bonds6.25 Sept. 1, 2037350 350 First mortgage bonds6.50 Aug. 1, 2038300 300 First mortgage bonds4.75 Aug. 15, 2041250 250 First mortgage bonds3.60 Sept. 15, 2042500 500 First mortgage bonds3.95 March 15, 2043250 250 First mortgage bonds4.30 March 15, 2044300 300 First mortgage bonds3.55 June 15, 2046250 250 First mortgage bonds3.80 June 15, 2047400 400 First mortgage bonds4.10 June 15, 2048350 350 First mortgage bonds4.05 Sept. 15, 2049400 400 First mortgage bonds3.20 March 1, 2050550 550 First mortgage bonds2.70 Jan. 15, 2051375 375 First mortgage bonds4.50 June 1, 2052400 400 First mortgage bonds (b)5.25 April 1, 2053850 850 First mortgage bonds (a)5.75 May 15, 2054750 — Unamortized discount(42)(41)Unamortized debt issuance cost(67)(59)Current maturities(250)— Total long-term debt$8,391 $7,450 First mortgage bonds (a) First mortgage bonds (b) First mortgage bonds (a) (a)2024 financing. (b)2023 financing. 2023 financing. 60 60 60 Table of Contents Table of Contents SPSFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds3.30 %June 15, 2024$— $150 First mortgage bonds3.30 June 15, 2024— 200 Unsecured senior notes6.00 Oct. 1, 2033100 100 Unsecured senior notes6.00 Oct. 1, 2036250 250 First mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds 3.75 June 15, 2049300 300 First mortgage bonds3.15 May 1, 2050350 350 First mortgage bonds3.15 May 1, 2050250 250 First mortgage bonds5.15 June 1, 2052200 200 First mortgage bonds (a)6.00 Sept. 15, 2053100 100 First mortgage bonds (b)6.00 June 1, 2054600 — Unamortized discount(14)(10)Unamortized debt issuance cost(35)(29)Current maturities— (350)Total long-term debt$3,551 $2,961 (a)2023 financing.(b)2024 financing.Other SubsidiariesFinancing InstrumentInterest RateMaturity Date20242023Various Eloigne affordable housing project notes0.00% - 8.00%2024 - 2055$27 $27 Current maturities(3)(2)Total long-term debt$24 $25 Maturities of long-term debt:(Millions of Dollars)2025$1,103 2026501 2027501 20281,133 2029503 Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60% First Mortgage Bonds Series due June 1, 2051 for $105 million. On a consolidated basis, Xcel Energy Inc.’s repurchase of NSP-Minnesota first mortgage bonds was accounted for as a debt extinguishment and resulted in a pre-tax gain of approximately $56 million, net of unamortized discount and debt issuance costs. Interest expense related to the repurchased bonds was immaterial for the year ended Dec. 31, 2024.Deferred Financing Costs — Deferred financing costs of approximately $235 million and $209 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2024 and 2023, respectively. Equity through DRIP and Benefits Program — Xcel Energy issued $67 million of equity in 2024 and $88 million of equity in 2023 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2022, 4.3 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.9 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, through this ATM program, Xcel Energy Inc. issued 3.1 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In 2024, 18.3 million shares of common stock were issued ($1.1 billion in net proceeds and $9 million in transaction fees paid).Forward Equity Agreements — In November 2024, Xcel Energy Inc. entered into forward sale agreements in connection with completed public offerings of 21.1 million shares of Xcel Energy common stock. The initial forward agreements were for 18.3 million shares with additional agreements for 2.8 million shares exercised at the option of the banking counterparties. At Dec. 31, 2024, the forward agreements could have been settled with physical delivery of 21.1 million common shares to the banking counterparties in exchange for cash of $1.37 billion. The agreements could also have been settled at Dec. 31, 2024 with delivery of approximately $94 million of cash or approximately 1.4 million shares of common stock to the banking counterparties, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.The forward price used to determine amounts due at settlement is calculated based on the November 2024 public offering price of $64.44 (net of underwriting fees), increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.Xcel Energy may settle the forward agreements at any time up to the maturity date of June 30, 2026. The cash proceeds, depending on the timing of future settlement, are expected to be approximately $1.36 billion.As initial pricing terms were based on market prices for Xcel Energy common stock, no amounts were recorded at the execution of the forward agreements. Stockholders’ equity equal to cash proceeds will be recorded at settlement.Capital Stock — Preferred stock authorized/outstanding:Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2024 and 2023Xcel Energy Inc.7,000,000 $100 — PSCo10,000,000 0.01 — SPS10,000,000 1.00 — SPSFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds3.30 %June 15, 2024$— $150 First mortgage bonds3.30 June 15, 2024— 200 Unsecured senior notes6.00 Oct. 1, 2033100 100 Unsecured senior notes6.00 Oct. 1, 2036250 250 First mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds 3.75 June 15, 2049300 300 First mortgage bonds3.15 May 1, 2050350 350 First mortgage bonds3.15 May 1, 2050250 250 First mortgage bonds5.15 June 1, 2052200 200 First mortgage bonds (a)6.00 Sept. 15, 2053100 100 First mortgage bonds (b)6.00 June 1, 2054600 — Unamortized discount(14)(10)Unamortized debt issuance cost(35)(29)Current maturities— (350)Total long-term debt$3,551 $2,961 (a)2023 financing.(b)2024 financing.Other SubsidiariesFinancing InstrumentInterest RateMaturity Date20242023Various Eloigne affordable housing project notes0.00% - 8.00%2024 - 2055$27 $27 Current maturities(3)(2)Total long-term debt$24 $25 Maturities of long-term debt:(Millions of Dollars)2025$1,103 2026501 2027501 20281,133 2029503 Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60% First Mortgage Bonds Series due June 1, 2051 for $105 million. On a consolidated basis, Xcel Energy Inc.’s repurchase of NSP-Minnesota first mortgage bonds was accounted for as a debt extinguishment and resulted in a pre-tax gain of approximately $56 million, net of unamortized discount and debt issuance costs. Interest expense related to the repurchased bonds was immaterial for the year ended Dec. 31, 2024.Deferred Financing Costs — Deferred financing costs of approximately $235 million and $209 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2024 and 2023, respectively. SPSFinancing InstrumentInterest RateMaturity Date20242023First mortgage bonds3.30 %June 15, 2024$— $150 First mortgage bonds3.30 June 15, 2024— 200 Unsecured senior notes6.00 Oct. 1, 2033100 100 Unsecured senior notes6.00 Oct. 1, 2036250 250 First mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds 3.75 June 15, 2049300 300 First mortgage bonds3.15 May 1, 2050350 350 First mortgage bonds3.15 May 1, 2050250 250 First mortgage bonds5.15 June 1, 2052200 200 First mortgage bonds (a)6.00 Sept. 15, 2053100 100 First mortgage bonds (b)6.00 June 1, 2054600 — Unamortized discount(14)(10)Unamortized debt issuance cost(35)(29)Current maturities— (350)Total long-term debt$3,551 $2,961 First mortgage bonds (a) First mortgage bonds (b) (a)2023 financing. 2023 financing. (b)2024 financing. Other SubsidiariesFinancing InstrumentInterest RateMaturity Date20242023Various Eloigne affordable housing project notes0.00% - 8.00%2024 - 2055$27 $27 Current maturities(3)(2)Total long-term debt$24 $25 Maturities of long-term debt: (Millions of Dollars)2025$1,103 2026501 2027501 20281,133 2029503 Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60% First Mortgage Bonds Series due June 1, 2051 for $105 million. On a consolidated basis, Xcel Energy Inc.’s repurchase of NSP-Minnesota first mortgage bonds was accounted for as a debt extinguishment and resulted in a pre-tax gain of approximately $56 million, net of unamortized discount and debt issuance costs. Interest expense related to the repurchased bonds was immaterial for the year ended Dec. 31, 2024. Deferred Financing Costs — Deferred financing costs of approximately $235 million and $209 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2024 and 2023, respectively. Equity through DRIP and Benefits Program — Xcel Energy issued $67 million of equity in 2024 and $88 million of equity in 2023 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2022, 4.3 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.9 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, through this ATM program, Xcel Energy Inc. issued 3.1 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In 2024, 18.3 million shares of common stock were issued ($1.1 billion in net proceeds and $9 million in transaction fees paid).Forward Equity Agreements — In November 2024, Xcel Energy Inc. entered into forward sale agreements in connection with completed public offerings of 21.1 million shares of Xcel Energy common stock. The initial forward agreements were for 18.3 million shares with additional agreements for 2.8 million shares exercised at the option of the banking counterparties. At Dec. 31, 2024, the forward agreements could have been settled with physical delivery of 21.1 million common shares to the banking counterparties in exchange for cash of $1.37 billion. The agreements could also have been settled at Dec. 31, 2024 with delivery of approximately $94 million of cash or approximately 1.4 million shares of common stock to the banking counterparties, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.The forward price used to determine amounts due at settlement is calculated based on the November 2024 public offering price of $64.44 (net of underwriting fees), increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.Xcel Energy may settle the forward agreements at any time up to the maturity date of June 30, 2026. The cash proceeds, depending on the timing of future settlement, are expected to be approximately $1.36 billion.As initial pricing terms were based on market prices for Xcel Energy common stock, no amounts were recorded at the execution of the forward agreements. Stockholders’ equity equal to cash proceeds will be recorded at settlement.Capital Stock — Preferred stock authorized/outstanding:Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2024 and 2023Xcel Energy Inc.7,000,000 $100 — PSCo10,000,000 0.01 — SPS10,000,000 1.00 — Equity through DRIP and Benefits Program — Xcel Energy issued $67 million of equity in 2024 and $88 million of equity in 2023 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock. ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2022, 4.3 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.9 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, through this ATM program, Xcel Energy Inc. issued 3.1 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In 2024, 18.3 million shares of common stock were issued ($1.1 billion in net proceeds and $9 million in transaction fees paid). Forward Equity Agreements — In November 2024, Xcel Energy Inc. entered into forward sale agreements in connection with completed public offerings of 21.1 million shares of Xcel Energy common stock. The initial forward agreements were for 18.3 million shares with additional agreements for 2.8 million shares exercised at the option of the banking counterparties. At Dec. 31, 2024, the forward agreements could have been settled with physical delivery of 21.1 million common shares to the banking counterparties in exchange for cash of $1.37 billion. The agreements could also have been settled at Dec. 31, 2024 with delivery of approximately $94 million of cash or approximately 1.4 million shares of common stock to the banking counterparties, if Xcel Energy unilaterally elected net cash or net share settlement, respectively. The forward price used to determine amounts due at settlement is calculated based on the November 2024 public offering price of $64.44 (net of underwriting fees), increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding. Xcel Energy may settle the forward agreements at any time up to the maturity date of June 30, 2026. The cash proceeds, depending on the timing of future settlement, are expected to be approximately $1.36 billion. As initial pricing terms were based on market prices for Xcel Energy common stock, no amounts were recorded at the execution of the forward agreements. Stockholders’ equity equal to cash proceeds will be recorded at settlement. Capital Stock — Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2024 and 2023Xcel Energy Inc.7,000,000 $100 — PSCo10,000,000 0.01 — SPS10,000,000 1.00 — 61 61 61 Table of Contents Table of Contents Xcel Energy Inc. had the following common stock authorized/outstanding:Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2024Common Stock Outstanding (Shares) as of Dec. 31, 20231,000,000,000 $2.50 574,365,598 554,941,703 Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2024:Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2024NSP-Minnesota47.6 %58.2 %53.0 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.4 (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.(b) Excludes short-term debt.(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,809 $17,490 $17,800 NSP-Wisconsin12 2,922 N/ASPS (a)592 7,789 N/A(a)May not pay a dividend that would cause a loss of its investment grade bond rating. Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2024:(Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota (a)52.4% of total capitalization$2,670 NSP-Wisconsin$225 150 PSCo1,300 1,200 SPS150 700 (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. 6. RevenuesRevenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2024(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,552 $1,299 $11 $4,862 C&I5,420 646 30 6,096 Other142 — 9 151 Total retail9,114 1,945 50 11,109 Wholesale645 — — 645 Transmission648 — — 648 Other64 175 — 239 Total revenue from contracts with customers10,471 2,120 50 12,641 Alternative revenue and other676 110 14 800 Total revenues$11,147 $2,230 $64 $13,441 Year Ended Dec. 31, 2023(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,560 $1,560 $59 $5,179 C&I5,703 833 30 6,566 Other150 — 13 163 Total retail9,413 2,393 102 11,908 Wholesale815 — — 815 Transmission649 — — 649 Other63 156 — 219 Total revenue from contracts with customers10,940 2,549 102 13,591 Alternative revenue and other506 96 13 615 Total revenues$11,446 $2,645 $115 $14,206 Year Ended Dec. 31, 2022(Millions of Dollars)ElectricNatural GasAll OtherTotalMajor revenue typesRevenue from contracts with customers:Residential$3,542 $1,814 $53 $5,409 C&I5,807 998 32 6,837 Other148 — 10 158 Total retail9,497 2,812 95 12,404 Wholesale1,354 — — 1,354 Transmission675 — — 675 Other97 178 — 275 Total revenue from contracts with customers11,623 2,990 95 14,708 Alternative revenue and other500 90 12 602 Total revenues$12,123 $3,080 $107 $15,310 Xcel Energy Inc. had the following common stock authorized/outstanding:Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2024Common Stock Outstanding (Shares) as of Dec. 31, 20231,000,000,000 $2.50 574,365,598 554,941,703 Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2024:Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio ActualLowHigh2024NSP-Minnesota47.6 %58.2 %53.0 %NSP-Wisconsin (a)52.5 N/A52.7 SPS (b)45.0 55.0 54.4 (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.(b) Excludes short-term debt.(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total CapitalizationNSP-Minnesota$1,809 $17,490 $17,800 NSP-Wisconsin12 2,922 N/ASPS (a)592 7,789 N/A(a)May not pay a dividend that would cause a loss of its investment grade bond rating. Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2024:(Millions of Dollars)Long-Term DebtShort-Term DebtNSP-Minnesota (a)52.4% of total capitalization$2,670 NSP-Wisconsin$225 150 PSCo1,300 1,200 SPS150 700 (a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. Xcel Energy Inc. had the following common stock authorized/outstanding:" }, { "status": "UNCHANGED", "current_title": "Opinions on the Financial Statements and Internal Control over Financial Reporting", "prior_title": "Opinions on the Financial Statements and Internal Control over Financial Reporting", "current_body": "We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the \"Company\") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the \"financial statements\"). We also have audited the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO." }, { "status": "UNCHANGED", "current_title": "Additional Periods for Which a One-Year Extension May Be Requested (c)", "prior_title": "Additional Periods for Which a One-Year Extension May Be Requested (c)", "current_body": "Xcel Energy Inc. (d) (a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. (b)Amounts authorized by state commissions in respective jurisdictions. Amounts authorized by state commissions in respective jurisdictions. (c)All extension requests are subject to majority bank group approval. All extension requests are subject to majority bank group approval. (d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million. The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million. If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2024, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2024: (Millions of Dollars)Credit Facility (a)Drawn (b)AvailableXcel Energy Inc.$1,500 $235 $1,265 PSCo700 115 585 NSP-Minnesota700 207 493 SPS500 145 355 NSP-Wisconsin150 35 115 Total$3,550 $737 $2,813" }, { "status": "UNCHANGED", "current_title": "Recovery Mechanisms", "prior_title": "Recovery Mechanisms", "current_body": "MechanismAdditional InformationCIP RiderRecovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.Customer Protection MechanismsMISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. DecouplingMeasures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers.FCARecovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota).Gas Utility Infrastructure Cost RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.Infrastructure RiderRecovers costs for investments in generation in South Dakota.Purchased Gas AdjustmentProvides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.Renewable Development Fund RiderAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.Renewable Energy RiderRecovers cost of renewable generation in North Dakota.RES RiderRecovers cost of renewable generation in Minnesota.Sales True-upMitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. State Energy Policy Electric RiderRecovers costs associated with the Prairie Island Legislation settlement and the Reliability Administrator/ Sustainable Building Guidelines in Minnesota.Transmission Cost Recovery RiderRecovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization." }, { "status": "UNCHANGED", "current_title": "Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.", "prior_title": "Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.", "current_body": "Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential reputational impact. Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to: •Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. •Failures in the availability, acquisition or transportation of fuel or other supplies. •Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns •Performance below expected or contracted levels of output or efficiency. •Availability of replacement or new equipment. •Availability of adequate water resources and ability to satisfy water intake and discharge requirements. •Inability to identify, manage properly or mitigate equipment defects. •Use of new or unproven technology. •Inability to use information effectively given the rapidly increasing volume of data. •Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources. •Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes. •Increased costs due to aging infrastructure. 15 15 15 Table of Contents Table of Contents Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services. Our utility operations are subject to long-term planning and project risks.Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate. Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules. Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks. Our utilities have physical and financial risks associated with wildfires.In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Also, the expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Wildfires could jeopardize Xcel Energy’s electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services. Our utility operations are subject to long-term planning and project risks.Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations. Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services." }, { "status": "UNCHANGED", "current_title": "We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.", "prior_title": "We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.", "current_body": "Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; impacts on the transportation of goods, and the generalized impact on the economy. We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak. 19 19 19 Table of Contents Table of Contents Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error. The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations.Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability. Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business. Generative Artificial Intelligence, such as large language models like ChatGPT, present a range of challenges and potential risks as we consider impacts to the business. These challenges involve navigating the complexities of creating and deploying AI models that generate content autonomously. Data privacy, legal concerns, and security issues are all risks as this technology continues to be adopted.Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability. While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures. Operations could be impacted by war, terrorism or other events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers. A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.A cybersecurity incident or security breach could have a material effect on our business.We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error." }, { "status": "UNCHANGED", "current_title": "Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives", "prior_title": "Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives", "current_body": "Xcel Energy 2025 Earnings Guidance — Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a) Key assumptions as compared with 2024 actual levels unless noted: •Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans. •Normal weather patterns for the year. •Weather-normalized retail electric sales are projected to increase ~3%. •Weather-normalized retail firm natural gas sales are projected to increase ~1%. •Capital rider revenue is projected to increase $260 million to $270 million (net of PTCs). •O&M expenses are projected to increase ~3%. •Depreciation expense is projected to increase approximately $210 million to $220 million. •Property taxes are projected to increase $55 million to $65 million. •Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income. •AFUDC - equity is projected to increase $110 million to $120 million. (a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS. Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:• Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).• Deliver annual dividend increases of 4% to 6%.• Target a dividend payout ratio of 50% to 60%.• Maintain senior secured debt credit ratings in the A range.ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSee the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATASee Item 15-1 for an index of financial statements included herein.See Note 15 to the consolidated financial statements for further information. Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives: • Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share). • Deliver annual dividend increases of 4% to 6%. • Target a dividend payout ratio of 50% to 60%. • Maintain senior secured debt credit ratings in the A range. ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference. ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Item 15-1 for an index of financial statements included herein. See Note 15 to the consolidated financial statements for further information. 43 43 43 Table of Contents Table of Contents" }, { "status": "UNCHANGED", "current_title": "Station, Location and Unit at Dec. 31, 2024", "prior_title": "Station, Location and Unit at Dec. 31, 2023", "current_body": "MW (a) (b) (c) (d) (d) (d) (d) (d) (d) (d) (d) (d) Grand Meadow-Mower County, MN, 67 Units (d) (d) (d) (d) (d) (d) (d) (d) (a)Summer 2024 net dependable capacity. Wind and solar is presented as net maximum capacity. (b)Based on NSP-Minnesota’s ownership of 59%. (c)RDF is made from municipal solid waste. (d)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, NSP-Minnesota’s wind facilities had a weighted-average capacity factor of 46%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500 (a)Summer 2024 net dependable capacity.(b)RDF is made from municipal solid waste.(c)Retired unit in 2024.PSCoStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Comanche-Pueblo, COUnit 2Coal1975330 Unit 3Coal2010500 (b)Craig-Craig, CO, 2 UnitsCoal1979 - 198082 (c)Hayden-Hayden, CO, 2 Units Coal1965 - 1976233 (d)Pawnee-Brush, CO, 1 UnitCoal1981505 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 Combustion Turbine:Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 20091,022 Manchief-Brush, CO, 2 UnitsNatural Gas2000250 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004592 Valmont-Boulder, CO, 3 unitsNatural Gas1973 - 2001119 Various locations, 5 UnitsNatural GasVarious128 Hydro:Cabin Creek-Georgetown, COPumped Storage, 2 UnitsHydro1967210 Various locations, 6 UnitsHydroVarious23 Wind:Rush Creek, CO, 300 unitsWind2018582 (e)Cheyenne Ridge, CO, 229 unitsWind2020477 (e)Total6,203 (a)Summer 2024 net dependable capacity. Wind is presented as net maximum capacity.(b)Based on PSCo’s ownership of 67%.(c)Based on PSCo’s ownership of 10%. (d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.(e)Net maximum capacity is attainable only when wind conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2024, PSCo’s wind facilities had a weighted-average capacity factor of 44%. NSP-WisconsinStation, Location and Unit at Dec. 31, 2024FuelInstalledMW (a)Steam:Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 French Island-La Crosse, WI, 2 UnitsWood/RDF1940 - 194816 (b)Combustion Turbine:French Island-La Crosse, WI, 2 UnitsOil1974119 Wheaton-Eau Claire, WI, 4 UnitsNatural Gas/Oil1973189 (c)Hydro:Various locations, 62 UnitsHydroVarious135 Total500" } ] }