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Commitments and Contingencies | 12 Months Ended
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Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract] |
Commitments and Contingencies | Legal Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred. Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada. One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is forthcoming. Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial. Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized $35 million of losses for the verdict in 2023, including estimated interest and other costs. In the fourth quarter of 2024, PSCo and CORE reached a settlement, PSCo paid CORE the agreed to amounts and all appeals and related actions have been dismissed. Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses. According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area. The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition. PSCo is aware of 307 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,087 plaintiffs. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. In September 2023, the Boulder County District Court Judge consolidated the pending lawsuits into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025. Discovery is now underway. In September 2024, the Judge presiding over the consolidated cases in Boulder County issued an order regarding the trial that resolves, on a preliminary basis, certain disputes over the structure of the September 2025 trial. The Court ruled that all Plaintiffs should be bound by a trial on liability unless they opt-out with good cause. The Court also ruled that liability and damages should be largely or entirely tried separately, meaning that common questions of law and fact regarding liability would be decided first, and a majority or all of the damages phase will occur separately following the liability phase of trial. The individual plaintiffs filed a motion for reconsideration of the opt-out portion of this order, which the Court denied in November 2024, confirming that plaintiffs will have to demonstrate good cause in order to opt out of the trial. The Court also denied PSCo’s request for a change in venue, ruling that the trial will take place in Boulder County. Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action filed before Jan. 1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles. Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages. In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire. 2024 Smokehouse Creek Fire Complex — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the “Smokehouse Creek Fire Complex”). The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed. According to the Texas A&M Forest Service’s Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres. SPS is aware of approximately 25 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. SPS has also received approximately 205 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 129 of those claims as of the date of this filing. In addition to filed complaints and claims made through SPS’ claims process, SPS has also received information from attorneys for claims related to the Smokehouse Creek Fire Complex which have not been submitted through the claims process and have also not been filed as lawsuits, and has reached settlement of a portion of those claims. SPS anticipates additional complaints and demands will be made. As of December 2024, SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex. Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care. Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent. Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy believes it is probable that it will incur a loss in connection with the Smokehouse Creek Fire Complex and accordingly has recorded a total of $215 million of estimated losses for the matter (before available insurance). Settlements reached as of the date of this filing total $76 million of expected loss payments, of which $35 million were paid in 2024, resulting in a remaining estimated liability of $180 million presented in other current liabilities as of Dec. 31, 2024. The cumulative estimated probable losses of $215 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) corresponds to the lower end of the range of Xcel Energy’s reasonably estimable range of losses, and is subject to change based on additional information. This $215 million estimate does not include, among other things, amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) compensation claims for damage to trees, railroad lines, or oil and gas equipment, or (v) other amounts that are not reasonably estimable. Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows. The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change. SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. SPS has recorded an insurance receivable, net of recoveries received, for $210 million, presented within prepayments and other current assets as of Dec. 31, 2024. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. Rate Matters and Other Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements. Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA. In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota. In May 2024, the ALJ recommended a customer refund of $34 million (less a portion of the proceeds received from the settlement with GE). The ALJ indicated that consideration of the $22 million of previously disallowed costs was not in the scope of their recommendation. In 2024, following contested case procedures, Xcel recognized a customer refund of $47 million for replacement power incurred during the outage. Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual FCA true-up petition to the MPUC. In 2024, the DOC recommended customer refunds for 2023 replacement power costs incurred during an outage at the Prairie Island generating station (October 2023 through February 2024). NSP-Minnesota estimates that customer refunds would be approximately $22 million if the DOC recommendations are applied to both 2023 and 2024. In September 2024, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota has recorded an estimated liability for a customer refund. The procedural schedule is as follows: •Xcel Energy testimony: May 1, 2025 •Intervenor direct testimony: July 2, 2025 •Rebuttal testimony: August 13, 2025 •ALJ Report: March 16, 2026 Cabin Creek Prudency Review — In 2015, the CPUC granted a CPCN for an $88 million upgrade project to increase the generating and storage capacity of the Cabin Creek hydroelectric storage facility, which anticipated project completion in 2020. Due to significant and unforeseen challenges, the project was not completed until 2023 and cost approximately $110 million. In July 2024, PSCo filed direct testimony in a prudency review for the upgrade project, outlining the project’s timelines, costs, benefits and challenges. In February 2025, PSCo received answer testimony from CPUC Staff and UCA including proposed disallowances, primarily for replacement power and lost capacity. CPUC Staff recommended a disallowance of $21 million and UCA’s testimony included recommendations for total disallowances ranging from $71 million to $138 million. PSCo will file its rebuttal testimony in March 2025, responding to answer testimony and continuing to assert that its actions related to the project were prudent, and that therefore no disallowance should be granted. The remainder of the procedural schedule includes: •Settlement testimony: April 4, 2025 •Hearing: April 17-18, 2025 •Statements of position: May 9, 2025 A final CPUC decision is expected in the second half of 2025. Environmental New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process. Site Remediation Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site. MGP, Landfill and Disposal Sites Xcel Energy is investigating, remediating or performing post-closure actions at 13 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below). Xcel Energy has approximately $20 million of remaining liabilities for resolution of these issues, however, the final outcome and timing are unknown. In addition, there may be regulatory recovery, insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred. Environmental Requirements — Water and Waste Coal Ash Regulation — Xcel Energy is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste. In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use. As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land. If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures. Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-generating facilities at a current estimated cost of at least $45 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms. Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-fueled generating facilities at estimated costs totaling approximately $100 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms. Xcel Energy continues to evaluate the 2024 updates to the CCR Rule, the interpretations of those updates and how they will apply to specific sites. Assessment of the recent updates to the CCR Rule and corresponding site investigation activities may result in updates to estimated costs as well as identification of additional required corrective actions. Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species. Estimated capital expenditures of approximately $50 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms. Environmental Requirements — Air Clean Air Act NOx Allowance Allocations — AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants. Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $3.5 billion and $3.2 billion for 2024 and 2023, respectively. Xcel Energy’s AROs were as follows:
(Millions of Dollars) |  | Jan. 1, 2024 |  | Amounts Incurred (a) |  | Amounts Settled |  | Accretion |  | Cash Flow Revisions (b) |  | Dec. 31, 2024
Electric |  |  |  |  |  |  |  |  |  |  |  |
Nuclear |  | $ | 2,107 |  |  | $ | — |  |  | $ | — |  |  | $ | 106 |  |  | $ | 263 |  |  | $ | 2,476 |
Wind |  | 526 |  |  | — |  |  | — |  |  | 19 |  |  | (36) |  |  | 509 |
Steam, hydro and other production |  | 361 |  |  | 109 |  |  | (6) |  |  | 18 |  |  | 13 |  |  | 495 |
Distribution |  | 49 |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  | 51 |
Natural gas |  |  |  |  |  |  |  |  |  |  |  |
Transmission and distribution |  | 172 |  |  | — |  |  | — |  |  | 8 |  |  | (1) |  |  | 179 |
Other |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous |  | 3 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 3 |
Total liability |  | $ | 3,218 |  |  | $ | 109 |  |  | $ | (6) |  |  | $ | 153 |  |  | $ | 239 |  |  | $ | 3,713 |
(a)Amounts incurred largely pertain to CCR coal ash regulations and new obligations associated with Sherco Solar Unit 1 , which was placed in service in 2024. (b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes were driven by updated assumptions in the NSP-Minnesota nuclear decommissioning triennial filing coupled with discount rate and escalation rate changes. Wind, steam, hydro and other production AROs were revised due to the results of the 2024 dismantling studies and changes in cost estimates to remediate ash containment facilities.
(Millions of Dollars) |  | Jan. 1, 2023 |  | Amounts Incurred (a) |  | Amounts Settled |  | Accretion |  | Cash Flow Revisions (b) |  | Dec. 31, 2023
Electric |  |  |  |  |  |  |  |  |  |  |  |
Nuclear |  | $ | 2,160 |  |  | $ | — |  |  | $ | — |  |  | $ | 105 |  |  | $ | (158) |  |  | $ | 2,107 |
Wind |  | 514 |  |  | 10 |  |  | — |  |  | 19 |  |  | (17) |  |  | 526 |
Steam, hydro and other production |  | 348 |  |  | — |  |  | (1) |  |  | 15 |  |  | (1) |  |  | 361 |
Distribution |  | 48 |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  | 49 |
Natural gas |  |  |  |  |  |  |  |  |  |  |  |
Transmission and distribution |  | 307 |  |  | — |  |  | — |  |  | 14 |  |  | (149) |  |  | 172 |
Other |  |  |  |  |  |  |  |  |  |  |  |
Miscellaneous |  | 3 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 3 |
Total liability |  | $ | 3,380 |  |  | $ | 10 |  |  | $ | (1) |  |  | $ | 154 |  |  | $ | (325) |  |  | $ | 3,218 |
(a)Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. (b)In 2023, AROs were revised for changes in timing and estimates of cash flows. Revisions in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were a result of updated gas line mileage and number of services, as well as changes to inflation and discount rate assumptions. Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2024. Therefore, an ARO was not recorded for these facilities. Nuclear Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $16.3 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $500 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $15.8 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government. NSP-Minnesota is subject to assessments of up to $166 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $25 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI for each of NSP-Minnesota’s two nuclear plant sites. The coverage limits are $2.8 billion for both Monticello and Prairie Island. NEIL also provides business interruption insurance coverage up to $490 million and $420 million at Monticello and Prairie Island, respectively, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of $19 million for business interruption insurance and $34 million for property damage insurance if losses exceed accumulated reserve funds. Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available. NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. In October 2023, a CON for additional storage at the Monticello site was approved by the MPUC to support extended operations to 2040. The Prairie Island dry-cask storage facility currently stores 52 of the 64 authorized casks. In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054. Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for PI Unit 1 and 2034 for PI Unit 2. In February 2025, the MPUC approved a settlement agreement which extends the retirement dates for planning purposes to 2050, 2053, and 2054 for Monticello, PI Unit 1, and PI Unit 2, respectively. Requests to update the authorized retirement dates are expected to be submitted to the MPUC in 2025. Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The most recent triennial decommissioning study was filed in December 2024. Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $3.5 billion and $3.2 billion of assets held in external decommissioning trusts at Dec. 31, 2024 and 2023, respectively. See Note 10 to the consolidated financial statements for additional discussion. Leases Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine whether the arrangement is an operating lease or a finance lease. ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current operating lease liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets. Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted average of 4.6%). For currently existing asset classes, Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from lease payments for the purposes of lease accounting and disclosure. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet. Operating lease ROU assets:
(Millions of Dollars) |  | Dec. 31, 2024 |  | Dec. 31, 2023
PPAs |  | $ | 1,802 |  |  | $ | 1,832 |
Other |  | 373 |  |  | 315 |
Gross operating lease ROU assets |  | 2,175 |  |  | 2,147 |
Accumulated amortization |  | (1,115) |  |  | (930) |
Net operating lease ROU assets |  | $ | 1,060 |  |  | $ | 1,217 |
ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements. PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO. Finance lease ROU assets:
(Millions of Dollars) |  | Dec. 31, 2024 |  | Dec. 31, 2023
Gas storage facilities |  | $ | 160 |  |  | $ | 160 |
Gas pipeline |  | 21 |  |  | 21 |
Gross finance lease ROU assets |  | 181 |  |  | 181 |
Accumulated amortization |  | (70) |  |  | (67) |
Net finance lease ROU assets |  | $ | 111 |  |  | $ | 114 |
Components of lease expense:
(Millions of Dollars) |  | 2024 |  | 2023 |  | 2022
Operating leases |  |  |  |  |  |
PPA capacity payments |  | $ | 228 |  |  | $ | 241 |  |  | $ | 241 |
Other operating leases (a) |  | 43 |  |  | 42 |  |  | 39 |
Total operating lease expense (b) |  | $ | 271 |  |  | $ | 283 |  |  | $ | 280 |
Finance leases |  |  |  |  |  |
Amortization of ROU assets |  | $ | 3 |  |  | $ | 3 |  |  | $ | 4 |
Interest expense on lease liability |  | 15 |  |  | 15 |  |  | 16 |
Total finance lease expense |  | $ | 18 |  |  | $ | 18 |  |  | $ | 20 |
(a)Includes short-term lease expense of $4 million, $3 million, and $6 million for 2024, 2023 and 2022, respectively. (b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. Commitments under operating and finance leases as of Dec. 31, 2024:
(Millions of Dollars) |  | PPA (a) (b) Operating Leases |  | Other Operating Leases |  | Total Operating Leases |  | Finance Leases (c)
2025 |  | $ | 240 |  |  | $ | 31 |  |  | $ | 271 |  |  | $ | 10 |
2026 |  | 210 |  |  | 33 |  |  | 243 |  |  | 9 |
2027 |  | 162 |  |  | 27 |  |  | 189 |  |  | 8 |
2028 |  | 107 |  |  | 27 |  |  | 134 |  |  | 8 |
2029 |  | 59 |  |  | 22 |  |  | 81 |  |  | 8 |
Thereafter |  | 199 |  |  | 238 |  |  | 437 |  |  | 165 |
Total minimum obligation |  | 977 |  |  | 378 |  |  | 1,355 |  |  | 208 |
Interest component of obligation |  | (115) |  |  | (146) |  |  | (261) |  |  | (146) |
Present value of minimum obligation |  | $ | 862 |  |  | 232 |  |  | 1,094 |  |  | 62 |
Less current portion |  |  |  |  |  | (227) |  |  | (2) |
Noncurrent operating and finance lease liabilities |  |  |  |  |  | $ | 867 |  |  | $ | 60 |
Weighted-average remaining lease term in years |  |  |  |  |  | 8.7 |  | 35.8
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b)PPA operating leases contractually expire at various dates through 2039. (c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO. PPAs and Fuel Contracts Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered, and may also include capacity payments. Certain non-lease PPAs with various expiration dates through 2041, contain minimum energy purchase commitments. Total energy payments on those contracts were $212 million, $214 million and $182 million in 2024, 2023 and 2022, respectively. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $81 million, $77 million and $75 million in 2024, 2023 and 2022, respectively. Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms. At Dec. 31, 2024, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these non-lease contracts, subject to availability, were as follows:
(Millions of Dollars) |  | Capacity |  | Energy (a)
2025 |  | $ | 51 |  |  | $ | 111 |
2026 |  | 34 |  |  | 64 |
2027 |  | 14 |  |  | 21 |
2028 |  | 6 |  |  | 22 |
2029 |  | 6 |  |  | 22 |
Thereafter |  | 2 |  |  | — |
Total |  | $ | 113 |  |  | $ | 240 |
(a)Excludes contingent energy payments for renewable energy PPAs. Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2025 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities delivered under these agreements. Estimated minimum purchases under these contracts as of Dec. 31, 2024:
(Millions of Dollars) |  | Coal |  | Nuclear fuel |  | Natural gas supply |  | Natural gas storage and transportation
2025 |  | $ | 337 |  |  | $ | 168 |  |  | $ | 420 |  |  | $ | 345 |
2026 |  | 130 |  |  | 62 |  |  | 11 |  |  | 350 |
2027 |  | 76 |  |  | 133 |  |  | — |  |  | 312 |
2028 |  | 1 |  |  | 19 |  |  | — |  |  | 185 |
2029 |  | 1 |  |  | 67 |  |  | — |  |  | 103 |
Thereafter |  | 1 |  |  | 49 |  |  | — |  |  | 632 |
Total |  | $ | 546 |  |  | $ | 498 |  |  | $ | 431 |  |  | $ | 1,927 |
VIEs PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity. In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP. Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance. The utility subsidiaries had approximately 3,751 MW of capacity under long-term PPAs as of both Dec. 31, 2024 and 2023, with entities that have been determined to be VIEs. These agreements have expiration dates through 2048. Fuel Contracts — SPS purchases all of its coal requirements for its Tolk plant from TUCO Inc. under contracts that will expire in December 2027. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs. SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance. Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships with affordable rental housing activities that qualify for low-income housing tax credits. Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities, consolidate these limited partnerships in their consolidated financial statements. Amounts reflected in Xcel Energy’s consolidated balance sheets for these investments include $40 million of assets and $34 million of liabilities at Dec. 31, 2024, and $41 million of assets and $35 million of liabilities at Dec. 31, 2023. Other Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount. As of Dec. 31, 2024 and 2023, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $93 million and $75 million at Dec. 31, 2024 and 2023, respectively. Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

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