XCEL ENERGY INCXEL
XCEL ENERGY INC Commitments Disclosure
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 open, which is the multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). In October 2025, a settlement in principle was reached, resulting in an immaterial loss consistent with previously accrued amounts. This settlement is subject to court approval.
Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire). 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 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.
PSCo received notice or otherwise became aware of 307 complaints on behalf of at least 4,087 plaintiffs, most of which also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints generally alleged that PSCo’s equipment ignited the Marshall Fire and asserted various causes of action under Colorado law. In addition to asserting claims against PSCo, Xcel Energy Inc. and Xcel Energy Services Inc., various plaintiffs, including insurance company plaintiffs, asserted claims against certain telecommunications companies (the Telecom Companies). In April 2025, most of the remaining plaintiffs amended their complaints to also assert claims against the Telecom Companies. In June 2025, the Boulder County District Court dismissed Xcel Energy Inc. from the complaints that named that entity as a defendant, due to lack of jurisdiction.
An initial trial on liability issues was scheduled to start in September 2025. Prior to trial, in September 2025, Xcel Energy, Qwest Corporation and Teleport Communications America, LLC reached settlement agreements in principle that resolve all claims asserted by the subrogation insurers, the public entity plaintiffs and individual plaintiffs, and require PSCo to make settlement payments of $640 million. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.
As a result of settlements as well as legal and other costs of the matter, PSCo recognized charges to earnings of $287 million and $12 million in the quarterly periods ended Sept. 30 and Dec. 31, 2025, respectively, after consideration of total costs expected to be reimbursed by insurance. As of February 2026, final settlement documentation has been executed with the subrogation insurers, the public entity plaintiffs and nearly all the individual plaintiffs, and nearly all have received payment. If complaints of the remaining individual plaintiffs who have not accepted a settlement or have otherwise stopped prosecuting their claims are not resolved, they may be subject to further litigation.
A remaining estimated liability of $5 million is presented in other current liabilities as of Dec. 31, 2025; no estimated liability was recognized as of Dec. 31, 2024. PSCo records insurance recoveries when it is deemed probable that recovery will occur, and PSCo can reasonably estimate the amount or range. Insurance receivables of $353 million related to settlements are presented in prepayments and other current assets as of Dec. 31, 2025; no such insurance receivables were recognized as of Dec. 31, 2024.
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 56 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints, which assert claims on behalf of one or more plaintiffs, 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. Of the 56 complaints, 22 have been resolved and dismissed.
SPS has received 296 claims through its claims process, net of duplicative, withdrawn and denied claims, and has reached final settlements on 223 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 approximately 101 claims which have not been submitted through the claims process and have also not been filed as lawsuits and has reached settlement of 79 of those claims through mediation.
SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex. Settlements have also been reached with the subrogated insurer plaintiffs as well as the three largest claims asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $382 million of expected loss payments, of which $374 million and $35 million were paid through Dec. 31, 2025 and 2024, respectively.
In December 2025, the Texas Attorney General’s office filed a lawsuit against SPS regarding the Smokehouse Creek Fire, seeking monetary damages and civil penalties for losses to property and wildlife resulting from the fires. In February 2026, pending resolution of the lawsuit, SPS and the Texas Attorney General’s office jointly filed a temporary injunction agreeing to certain distribution pole replacement procedures, largely consistent with current procedures.
Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy has recorded $430 million of total estimated losses for the matter (before available insurance). A remaining estimated liability of $56 million and $180 million is presented in other current liabilities as of Dec. 31, 2025 and 2024, respectively.
The cumulative estimated probable losses of $430 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the total of actual settlements reached to date plus the low end of the range for remaining reasonably estimable losses, and is subject to change as additional information becomes available. This $430 million estimate does not include 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) unsettled compensation claims for damage to trees and 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, including whether additional complaints and demands may be made. 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.
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.
SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. Insurance receivables for estimated losses of approximately $195 million and $210 million, net of recoveries received are presented in prepayments and other current assets as of Dec. 31, 2025 and 2024, respectively. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.
Nuclear Antitrust Class Action — A class action complaint was filed in federal court for the District of Maryland in July 2025, alleging violations of the Sherman Antitrust Act in establishing wages for employees at nuclear facilities since 2003. The amended complaint names 46 defendants, including 45 entities that allegedly “own and/or operate all 54 commercial nuclear power plants in the United States,” including Xcel Energy Inc., Xcel Energy Services Inc., and NSP-Minnesota. NSP-Minnesota owns and operates two nuclear facilities in Minnesota, and disputes the allegations set forth against it and the other company entities. The litigation is ongoing, and Xcel Energy assesses the risk of a material impact to its consolidated financial statements as remote.
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.
Prairie Island Outage Prudency Review — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC. In a response to that petition, intervenors recommended refunds for replacement power costs related to an outage at the Prairie Island generating station (October 2023 through February 2024).
In a September 2024 decision, 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 recorded an estimated liability for a customer refund in 2024.
In May 2025, in the resulting case currently before an ALJ to determine the refund amount, NSP-Minnesota submitted direct testimony asserting that no more than $6 million of customer refunds are warranted for the outage.
Rebuttal and surrebuttal testimony were filed in August and September 2025 and final briefs were filed in January 2026. Intervenor briefs included recommendations for customer refunds of approximately $40 million to account for the total impact of the outage on 2023 and 2024. An ALJ report is expected in March 2026, with a MPUC decision expected in the second quarter of 2026.
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 11 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 $15 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 generating facilities at estimated costs totaling approximately $105 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
Xcel Energy continues to perform site investigation activities related to the CCR Rule, which may result in updates to estimated costs as well as identification of additional required corrective actions.
In February 2026, the EPA issued a final rule amending the CCR Legacy rule. The ruling extends deadlines for various regulatory actions and clarifies previous information regarding implementation of the rule. Xcel Energy is still evaluating the final rule, but anticipates impacts to be consistent with prior accruals.
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 $3.9 billion and $3.5 billion for 2025 and 2024, respectively.
Xcel Energy’s AROs were as follows:
| (Millions of Dollars) | Jan. 1, 2025 | Amounts Incurred (a) | Accretion | Cash Flow Revisions (b) | Dec. 31, 2025 | |||||||||||||||||||||||||||
| Electric | ||||||||||||||||||||||||||||||||
| Nuclear | $ | 2,476 | $ | — | $ | 127 | $ | — | $ | 2,603 | ||||||||||||||||||||||
| Wind | 509 | — | 18 | (12) | 515 | |||||||||||||||||||||||||||
| Steam, hydro and other production | 495 | 16 | 21 | (1) | 531 | |||||||||||||||||||||||||||
| Distribution | 51 | — | 3 | — | 54 | |||||||||||||||||||||||||||
| Natural gas | ||||||||||||||||||||||||||||||||
| Transmission and distribution | 179 | — | 9 | (6) | 182 | |||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||
| Miscellaneous | 3 | — | — | — | 3 | |||||||||||||||||||||||||||
| Total liability | $ | 3,713 | $ | 16 | $ | 178 | $ | (19) | $ | 3,888 | ||||||||||||||||||||||
(a)Amounts incurred largely pertain to obligations associated with new solar facilities.
(b)In 2025, AROs were revised for changes in timing and estimates of cash flows. Wind was revised due to the repowering of two wind facilities in NSP-Minnesota.
| (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.
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, 2025. 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 $21 million for business interruption insurance and $38 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. In October 2023, the MPUC approved additional storage at the Monticello site to support extended operations to 2040. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life in 2050.
In October 2025, the MPUC approved additional storage at the Prairie Island site to support extended operations 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 Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. As of Dec. 31, 2025, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2053, 2054 and 2050, based off the approved 2024-2040 Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates once additional approvals have been received. Approvals are expected in the third quarter of 2026.
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 November 2024 and approved by the MPUC in May 2025.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $3.9 billion and $3.5 billion of assets held in external decommissioning trusts at Dec. 31, 2025 and 2024, respectively.
See Note 10 to the consolidated financial statements for additional discussion.
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 2040, contain minimum energy purchase commitments. Total energy payments on those contracts were $111 million, $212 million and $214 million in 2025, 2024 and 2023, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $49 million, $81 million and $77 million in 2025, 2024 and 2023, 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, 2025, 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) | ||||||||||||
| 2026 | $ | 34 | $ | 99 | ||||||||||
| 2027 | 31 | 72 | ||||||||||||
| 2028 | 25 | 72 | ||||||||||||
| 2029 | 25 | 70 | ||||||||||||
| 2030 | 20 | 51 | ||||||||||||
| Thereafter | 206 | 411 | ||||||||||||
| Total | $ | 341 | $ | 775 | ||||||||||
(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 2026 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, 2025:
| (Millions of Dollars) | Coal | Nuclear fuel | Natural gas supply | Natural gas storage and transportation | ||||||||||||||||||||||
| 2026 | $ | 300 | $ | 67 | $ | 365 | $ | 399 | ||||||||||||||||||
| 2027 | 135 | 148 | 3 | 349 | ||||||||||||||||||||||
| 2028 | 11 | 35 | 1 | 215 | ||||||||||||||||||||||
| 2029 | 1 | 129 | — | 127 | ||||||||||||||||||||||
| 2030 | 1 | 24 | — | 72 | ||||||||||||||||||||||
| Thereafter | — | 49 | — | 717 | ||||||||||||||||||||||
| Total | $ | 448 | $ | 452 | $ | 369 | $ | 1,879 | ||||||||||||||||||
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 3,476 MW and 3,751 MW of capacity under long-term PPAs at Dec. 31, 2025 and 2024, respectively, 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 $39 million of assets and $34 million of liabilities at Dec. 31, 2025, and $40 million of assets and $34 million of liabilities at Dec. 31, 2024.
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, 2025 and 2024, 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 $120 million and $93 million at Dec. 31, 2025 and 2024, 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 and transaction authorization. Additionally, Xcel Energy Inc. and its subsidiaries have agreed to reimburse purchasers of the subsidiaries’ transferable tax credits for any unexpected reductions or IRS disallowances.
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.
Historical Timeline
| Fiscal Year | Filed | |
|---|---|---|
| 2025 | Feb 25, 2026 | Showing above |
| 2024 | Feb 27, 2025 | |
| 2023 | Feb 21, 2024 | |
| 2022 | Feb 23, 2023 | |
| 2021 | Feb 23, 2022 | |
| 2020 | Feb 17, 2021 | |
| 2019 | Feb 21, 2020 | |
| 2018 | Feb 22, 2019 | |
| 2017 | Feb 23, 2018 | |
| 2016 | Feb 24, 2017 | |
| 2015 | Feb 19, 2016 | |
About Commitments Disclosures
Commitments and contingencies disclosures catalog a company's off-balance-sheet obligations and legal exposures — purchase commitments, guarantee arrangements, pending litigation, and regulatory proceedings. These items represent potential future cash outflows that may not appear as liabilities on the balance sheet until they become probable and estimable.
Key signals: litigation reserves and disclosed loss ranges quantify management's estimate of legal exposure, but unquantified "reasonably possible" losses often represent the larger risk. Watch for changes in language around pending cases — shifts from "remote" to "reasonably possible" or increases in estimated loss ranges signal deteriorating outcomes. Unconditional purchase obligations and take-or-pay contracts create fixed cost structures that reduce operational flexibility. Guarantee arrangements for subsidiaries or joint ventures can create cascading obligations. Compare the total commitment schedule against projected free cash flow to assess whether the company can meet its obligations without additional financing.