NORTHERN STATES POWER CO, 10-K filed on 2/27/2025
Annual Report
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Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2024
Feb. 27, 2025
Jun. 30, 2024
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2024    
Document Transition Report false    
Entity File Number 001-31387    
Entity Incorporation, State or Country Code MN    
Entity Tax Identification Number 41-1967505    
Entity Address, Address Line One 414 Nicollet Mall    
Entity Address, City or Town Minneapolis    
Entity Address, State or Province MN    
Entity Address, Postal Zip Code 55401    
City Area Code (612)    
Local Phone Number 330-5500    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Non-accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag false    
Entity Shell Company false    
Entity Common Stock, Shares Outstanding   1,000,000  
Entity Registrant Name NORTHERN STATES POWER CO    
Entity Central Index Key 0001123852    
Current Fiscal Year End Date --12-31    
Document Fiscal Year Focus 2024    
Document Fiscal Period Focus FY    
Amendment Flag false    
Entity Public Float     $ 0
Document Information [Line Items]      
Document Financial Statement Error Correction [Flag] false    
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Audit Information
 12 Months Ended
Dec. 31, 2024
Auditor Information [Abstract]  
Auditor Name DELOITTE & TOUCHE LLP
Auditor Firm ID 34
Auditor Location Minneapolis, Minnesota
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CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Operating revenues      
Electric, non-affiliates $ 4,639 $ 4,748 $ 5,103
Electric, affiliates 460 493 514
Natural gas 653 754 1,022
Other 15 48 45
Total operating revenues 5,767 6,043 6,684
Operating expenses      
Electric fuel and purchased power 1,988 2,069 2,416
Cost of natural gas sold and transported 295 466 741
Cost of sales — other 4 30 26
Operating and maintenance expenses 1,271 1,244 1,228
Conservation and demand side management expenses 181 118 163
Depreciation and amortization 1,106 981 1,014
Taxes (other than income taxes) 212 237 276
Workforce reduction expenses 0 32 0
Total operating expenses 5,057 5,177 5,864
Operating income 710 866 820
Other income (expense), net 11 0 (7)
Allowance for funds used during construction — equity 53 36 29
Interest charges and financing costs      
Interest charges and other financing costs 363 325 291
Allowance for funds used during construction — debt (26) (21) (12)
Total interest charges and financing costs 337 304 279
Income before income taxes 437 598 563
Income tax benefit (356) (109) (112)
Net income $ 793 $ 707 $ 675
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Comprehensive income:      
Net income $ 793 $ 707 $ 675
Derivative instruments:      
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification and Tax 12 (3) 0
Other Comprehensive Income (Loss), Net Investment Hedge, Gain (Loss), Reclassification, before Tax 0 1 1
Total other comprehensive income (loss) 12 (2) 2
Total comprehensive income 805 705 677
Net pension and retiree medical gain arising during the period, net of tax $ 0 $ 0 $ 1
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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Operating activities      
Net income $ 793 $ 707 $ 675
Adjustments to reconcile net income to cash provided by operating activities:      
Depreciation and amortization 1,112 988 1,021
Nuclear fuel amortization 106 96 118
Deferred income taxes 141 214 (214)
Allowance for equity funds used during construction (53) (36) (29)
Provision for bad debts 15 30 21
Changes in operating assets and liabilities:      
Accounts receivable (42) 1 (102)
Accrued unbilled revenues 18 82 (53)
Inventories (24) (27) (85)
Other current assets (48) (19) (4)
Accounts payable 59 (64) 46
Net regulatory assets and liabilities 108 287 443
Other current liabilities (214) 56 39
Pension and other employee benefit obligations (42) (15) (11)
Other, net (11) 1 6
Net cash provided by operating activities 1,918 2,301 1,871
Investing activities      
Capital/construction expenditures (2,803) (2,282) (1,901)
Purchase of investment securities (998) (994) (1,332)
Proceeds from the sale of investment securities 961 959 1,297
Investments in utility money pool arrangement (390) (300) (1,522)
Repayments from utility money pool arrangement 414 243 1,613
Other, net (3) (3) 6
Net cash used in investing activities (2,819) (2,377) (1,839)
Financing activities      
Proceeds from (repayments of) short-term borrowings, net 30 (42) 207
Borrowings under utility money pool arrangement 271 302 6
Repayments under utility money pool arrangement (271) (302) (6)
Proceeds from issuance of long-term debt 687 783 489
Repayment of long-term debt 0 (400) (300)
Capital contributions from parent 715 351 124
Dividends paid to parent (494) (647) (560)
Net cash provided by (used in) financing activities 938 45 (40)
Net change in cash, cash equivalents and restricted cash 37 (31) (8)
Cash, cash equivalents and restricted cash at beginning of period 34 65 73
Cash, cash equivalents and restricted cash at end of period 71 34 65
Supplemental disclosure of cash flow information:      
Cash paid for interest (net of amounts capitalized) (313) (294) (268)
Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers 446 256 (100)
Supplemental disclosure of non-cash investing and financing transactions:      
Accrued property, plant and equipment additions 500 218 208
Inventory transfers to property, plant and equipment 41 55 10
Operating lease right-of-use assets 39 216 1
Allowance for equity funds used during construction $ 53 $ 36 $ 29
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CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Current assets    
Cash, cash equivalents and restricted cash at end of period $ 71 $ 34
Investments in money pool arrangements 33 57
Accrued unbilled revenues 272 290
Inventories 339 356
Regulatory assets 364 250
Derivative instruments 36 50
Prepayments and other 139 87
Total current assets 1,785 1,629
Property, plant and equipment, net 20,860 18,757
Other assets    
Nuclear decommissioning fund and other investments 3,548 3,262
Regulatory assets 813 837
Derivative instruments 67 61
Operating lease right-of-use assets 393 439
Other 19 16
Total other assets 4,840 4,615
Total assets 27,485 25,001
Current liabilities    
Current portion of long-term debt 250 0
Short-term debt 195 165
Regulatory liabilities [1] 543 300
Taxes accrued 221 223
Accrued interest 90 79
Dividends payable to parent 80 121
Derivative instruments 31 44
Operating lease liabilities 97 91
Other 150 351
Total current liabilities 2,388 2,042
Deferred credits and other liabilities    
Deferred income taxes 2,238 1,992
Deferred investment tax credits 13 14
Regulatory liabilities [1] 2,155 2,097
Asset retirement obligations 3,073 2,658
Derivative instruments 77 86
Pension and employee benefit obligations 151 168
Operating lease liabilities 317 372
Other 28 35
Total deferred credits and other liabilities 8,052 7,422
Commitments and contingencies
Capitalization    
Common Stock, Value, Issued $ 0 $ 0
Common Stock, Shares Authorized 5,000,000 5,000,000
Common Stock, Par or Stated Value Per Share $ 0.01 $ 0.01
Common stock outstanding (shares) 1,000,000 1,000,000
Additional paid in capital $ 6,399 $ 5,686
Retained earnings 2,881 2,541
Accumulated other comprehensive loss (8) (20)
Total common stockholder's equity 9,272 8,207
Total liabilities and equity 27,485 25,001
Related Party    
Current assets    
Accounts receivable, net 1 15
Current liabilities    
Accounts payable 100 89
Capitalization    
Long-term debt 166 0
Affiliated Entity    
Current liabilities    
Accounts payable 631 579
Nonrelated Party    
Current assets    
Accounts receivable, net 530 490
Capitalization    
Long-term debt $ 7,607 $ 7,330
[1] Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($)
$ in Millions
Total
Common stock
Additional Paid In Capital
Retained Earnings
AOCI Attributable to Parent
Balance at beginning of period (shares) at Dec. 31, 2021   1,000,000      
Balance at beginning of period at Dec. 31, 2021 $ 7,573 $ 0 $ 5,202 $ 2,391 $ (20)
Increase (Decrease) in Stockholder's Equity          
Net income 675     675  
Other comprehensive income 2       2
Dividends declared to parent (586)     (586)  
Contribution of capital by parent 172   172    
Balance at end of period (shares) at Dec. 31, 2022   1,000,000      
Balance at end of period at Dec. 31, 2022 7,836 $ 0 5,374 2,480 (18)
Increase (Decrease) in Stockholder's Equity          
Net income 707     707  
Other comprehensive income (2)       (2)
Dividends declared to parent (646)     (646)  
Contribution of capital by parent $ 312   312    
Balance at end of period (shares) at Dec. 31, 2023 1,000,000 1,000,000      
Balance at end of period at Dec. 31, 2023 $ 8,207 $ 0 5,686 2,541 (20)
Increase (Decrease) in Stockholder's Equity          
Net income 793     793  
Other comprehensive income 12       12
Dividends declared to parent (453)     (453)  
Contribution of capital by parent $ 713   713    
Balance at end of period (shares) at Dec. 31, 2024 1,000,000 1,000,000      
Balance at end of period at Dec. 31, 2024 $ 9,272 $ 0 $ 6,399 $ 2,881 $ (8)
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Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies
General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.
NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.
Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of operating costs associated with these facilities is included in its consolidated statements of income.
NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s 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.
NSP-Minnesota 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 — NSP-Minnesota 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 and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — NSP-Minnesota accounts 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, NSP-Minnesota 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 NSP-Minnesota’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — NSP-Minnesota 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 NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its 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. NSP-Minnesota 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.
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 NSP-Minnesota tax elections. For tax credits otherwise eligible to be recognized when earned, NSP-Minnesota 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 regulatory mechanisms.
NSP-Minnesota 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, including NSP-Minnesota 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 3.9% for 2024, 3.7% for 2023 and 4.0% for 2022.
See Note 3 for further information.
AROs — NSP-Minnesota 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 10 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 8 and 10 for further information.
Benefit Plans and Other Postretirement Benefits — NSP-Minnesota 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 9 for further information.
Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota 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 NSP-Minnesota’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 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota 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.
NSP-Minnesota recognizes 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 RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.
NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
See Note 6 for further information.
Cash and Cash Equivalents — NSP-Minnesota 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. NSP-Minnesota 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 $42 million and $48 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, 2023
Inventories
Materials and supplies$234 $219 
Fuel81 105 
Natural gas24 32 
Total inventories$339 $356 
Fair Value Measurements — NSP-Minnesota 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 8 and 9 for further information.
Derivative Instruments — NSP-Minnesota 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 — NSP-Minnesota 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 8 for further information.
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 NSP-Minnesota’s 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 8 for further information.
Other Utility Items
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 NSP-Minnesota’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 — NSP-Minnesota 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. An inventory accounting model is used to account for RECs.
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.
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Accounting Pronouncements
 12 Months Ended
Dec. 31, 2024
Accounting Standards Update and Change in Accounting Principle [Abstract]  
Accounting Pronouncements
Recently Adopted
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. NSP-Minnesota implemented this guidance on a retrospective basis in the year ended Dec. 31, 2024. The adoption impacts were not material.
See Note 12 for further information.
Recently Issued
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 NSP-Minnesota 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. NSP-Minnesota 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. NSP-Minnesota is currently evaluating the impact of implementing the new disclosure guidance.
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Property Plant and Equipment Property Plant and Equipment
 12 Months Ended
Dec. 31, 2024
Property, Plant and Equipment [Abstract]  
Property, Plant and Equipment Disclosure
Major classes of property, plant and equipment
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
Property, plant and equipment, net
Electric plant$23,218 $21,206 
Natural gas plant2,472 2,256 
Common and other property1,450 1,301 
Plant to be retired (a)
554 604 
CWIP1,522 1,085 
Total property, plant and equipment29,216 26,452 
Less accumulated depreciation(8,753)(8,044)
Nuclear fuel3,491 3,337 
Less accumulated amortization(3,094)(2,988)
Property, plant and equipment, net$20,860 $18,757 
(a)Amounts include Sherco 1 and 3 and A.S. King. Balance is presented net of accumulated depreciation.
Joint Ownership of Generation and Transmission Facilities
Jointly owned assets as of Dec. 31, 2024:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
Electric 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 (a)
$1,745 $798 
(a)Projects additionally include $10 million in CWIP.
NSPM
v3.25.0.1
Regulatory Assets and Liabilities
 12 Months Ended
Dec. 31, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets and Liabilities
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. NSP-Minnesota 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, 2023
Regulatory AssetsCurrentNoncurrentCurrentNoncurrent
Pension and retiree medical obligations9 Various$21 $339 $18 $340 
Recoverable deferred taxes on AFUDCPlant lives— 137 — 127 
Excess deferred taxes — TCJA
7Various8 87 8 96 
MISO capacity revenue tracker
One to two years
63 45 36 26 
Prairie Island extended power uprate
10 years
4 34 4 38 
Benson biomass PPA termination and asset purchase
Four years
10 26 10 36 
Deferred purchased natural gas
One to two years
51 25 16 58 
Sales true-up and revenue decoupling
One to two years
60 23 7 2 
Nuclear refueling outage costs1
One to two years
51 20 43 19 
Contract valuation adjustments (a)
1, 8Term of related contract7 16 9 22 
Purchased power contracts costsTerm of related contract1 16 1 20 
Conservation programs (b)
1
One to two years
8 15 6 19 
Renewable resources and environmental initiatives
Less than one year
34 — 38 — 
Gas pipeline inspection and remediation costs
Less than one year
30 — 37 — 
Other Various16 30 17 34 
Total regulatory assets$364 $813 $250 $837 
(a)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(b)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, 2023
Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Deferred income tax adjustments and TCJA refunds (a)
7Various$5 $1,105 $5 $1,157 
Plant removal costs1, 10Various— 815 — 741 
Net AROs (b)
Various— 161 — 90 
Renewable resources and environmental initiativesVarious16 38 9 27 
Deferred natural gas and electric energy/fuel costs (c)
One to two years
348 12 143 — 
Conservation programs
Less than one year
41 — 27 — 
Contract valuation adjustments (d)
1, 8
Less than one year
21 — 16 — 
Other Various112 24 100 82 
Total regulatory liabilities (e)
$543 $2,155 $300 $2,097 
(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.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes Nuclear PTCs.
(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
(e)Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities.
NSP-Minnesota’s regulatory assets not earning a return include past expenditures of $562 million and $479 million at Dec. 31, 2024 and 2023, respectively, which predominately relate to purchased natural gas (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.
v3.25.0.1
Borrowings and Other Financing Instruments
 12 Months Ended
Dec. 31, 2024
Debt Disclosure [Abstract]  
Borrowings and Other Financing Instruments
Short-Term Borrowings
NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31
202420232022
Borrowing limit$250 $250 $250 $250 
Amount outstanding at period end— — — — 
Average amount outstanding31 10 17 — 
Maximum amount outstanding139 139 135 4 
Weighted average interest rate, computed on a daily basis4.62 %4.82 %4.97 %3.87 %
Weighted average interest rate at period endN/AN/AN/AN/A
Commercial Paper — Commercial paper outstanding:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31
202420232022
Borrowing limit$700 $700 $700 $700 
Amount outstanding at period end195 195 165 207 
Average amount outstanding24 54 92 21 
Maximum amount outstanding215 400 441 290 
Weighted average interest rate, computed on a daily basis4.62 %5.39 %4.99 %4.14 %
Weighted average interest rate at end of period4.63 4.63 5.47 4.64 
Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2024 and 2023, there were $12 million and $15 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use commercial paper programs to fulfill short-term funding needs, NSP-Minnesota 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.
Features of NSP-Minnesota’s credit facility:
Debt-to-Total Capitalization Ratio (a)
Amount Facility May Be Increased (millions of dollars)
Additional Periods for Which a One-Year Extension May Be Requested (b)
20242023
47.0 %47.7 %$150 2 
(a)The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b)All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that NSP-Minnesota would be in default on its borrowings under the facility if it or any of its subsidiaries whose total assets exceed 15% of NSP-Minnesota’s consolidated total assets, default on indebtedness in an aggregate principal amount exceeding $75 million.
If NSP-Minnesota does 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, NSP-Minnesota was in compliance with the financial covenant on its debt agreements.
NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2024 (in millions of dollars):
Credit Facility (a)
Drawn (b)
Available
$700 $207 $493 
(a)This credit facility matures 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 facility. NSP-Minnesota had no direct advances on the facility outstanding at Dec. 31, 2024 and 2023.
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, and 2023 NSP-Minnesota had $74 million and $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement, respectively.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of NSP-Minnesota is subject to the lien of its first mortgage indenture 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 NSP-Minnesota as of Dec. 31 (in millions of dollars):
Financing InstrumentInterest RateMaturity Date20242023
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 bonds (a)
2.60 June 1, 2051700 700 
First mortgage bonds3.20 April 1, 2052425 425 
First mortgage bonds4.50 June 1, 2052500 500 
First mortgage bonds (b)
5.10 May 15, 2053800 800 
First mortgage bonds (c)
5.40 March 15, 2054700 — 
Other long-term debt2 2 
Long-term debt — related parties principal amount outstanding (a)
2.60 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)During 2024, Xcel Energy Inc. purchased a portion of these NSP-Minnesota first mortgage bonds for $105 million. Interest expense related to these repurchased bonds was immaterial for the year ended Dec. 31, 2024.
(b)2023 financing.
(c)2024 financing.
Maturities of long-term debt are as follows:
(Millions of Dollars)
2025$250 
2026— 
2027— 
2028150 
2029— 
Dividend Restrictions — NSP-Minnesota’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividend payments are solely to be paid from retained earnings.
NSP-Minnesota’s state regulatory commissions additionally impose dividend limitations, 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 Actual
LowHigh2024
47.6 %58.2 %53.0 %
Unrestricted Retained EarningsTotal CapitalizationLimit on Total Capitalization
$1,809  million$17,490  million$17,800  million
v3.25.0.1
Revenues
 12 Months Ended
Dec. 31, 2024
Revenue from Contract with Customer [Abstract]  
Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consisted of the following:
Year Ended Dec. 31, 2024
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,496 $328 $7 $1,831 
C&I2,191 221 — 2,412 
Other36 — 8 44 
Total retail3,723 549 15 4,287 
Wholesale319 — — 319 
Transmission262 — — 262 
Interchange and other446 31 — 477 
Total revenue from contracts with customers4,750 580 15 5,345 
Alternative revenue and other349 73 — 422 
Total revenues$5,099 $653 $15 $5,767 
Year Ended Dec. 31, 2023
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,524 $368 $41 $1,933 
C&I2,298 309 — 2,607 
Other34 — 7 41 
Total retail3,856 677 48 4,581 
Wholesale354 — — 354 
Transmission263 — — 263 
Interchange and other493 18 — 511 
Total revenue from contracts with customers4,966 695 48 5,709 
Alternative revenue and other275 59 — 334 
Total revenues$5,241 $754 $48 $6,043 
Year Ended Dec. 31, 2022
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,463 $510 $38 $2,011 
C&I2,376 433 — 2,809 
Other38 — 7 45 
Total retail3,877 943 45 4,865 
Wholesale668 — — 668 
Transmission287 — — 287 
Interchange and other529 19 — 548 
Total revenue from contracts with customers5,361 962 45 6,368 
Alternative revenue and other256 60 — 316 
Total revenues$5,617 $1,022 $45 $6,684 
v3.25.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2024
Income Tax Disclosure [Abstract]  
Income Taxes
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31:
202420232022
Federal statutory rate21.0 %21.0 %21.0 %
State income tax on pretax income, net of federal tax effect7.1 7.0 7.0 
Increases (decreases) in tax from:
PTCs (a)
(99.4)(39.5)(39.6)
Plant regulatory differences (b)
(9.2)(5.7)(6.7)
Other tax credits, net NOL & tax credit allowances(1.9)(1.3)(1.3)
Other, net0.9 0.3 (0.3)
Effective income tax rate(81.5)%(18.2)%(19.9)%
(a)Wind, Solar, and Nuclear PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings. Nuclear PTCs, newly available in 2024, resulted in benefits of 39.5% to the ETR for the year ended Dec. 31, 2024.
(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)202420232022
Current federal tax (benefit) expense $(149)$(154)$70 
Current state tax (benefit) expense(25)3 26 
Current change in unrecognized tax expense (benefit)3 (21)8 
Deferred federal tax (benefit) expense(244)5 (237)
Deferred state tax expense61 51 23 
Deferred change in unrecognized tax (benefit) expense(1)8 — 
Deferred ITCs(1)(1)(2)
Total income tax benefit$(356)$(109)$(112)
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)202420232022
Deferred tax expense (benefit) excluding items below$246 $326 (283)
Adjustments to deferred income taxes for tax credit cash transfers (a)
(325)(150)— 
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities     
(99)(114)70 
Tax (expense) benefit allocated to other comprehensive income and other(6)2 (1)
Deferred tax (benefit) expense$(184)$64 $(214)
(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.
Components of the net deferred tax liability as of Dec. 31:
(Millions of Dollars)2024
2023 (a)
Deferred tax liabilities:
Differences between book and tax bases of property$3,150 $2,938 
Regulatory assets234 173 
Operating lease assets115 129 
Pension expense67 64 
Deferred fuel costs21 20 
Other21 9 
Total deferred tax liabilities$3,608 $3,333 
Deferred tax assets:
Tax credit carryforward$875 $832 
Regulatory liabilities358 306 
Operating lease liabilities115 129 
Rate refund10 59 
NOL and tax credit valuation allowances(68)(57)
Other employee benefits28 31 
Deferred ITCs4 4 
Other48 37 
Total deferred tax assets$1,370 $1,341 
Net deferred tax liability$2,238 $1,992 
(a)Prior periods have been reclassified to conform to current year presentation.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)20242023
Federal tax credit carryforwards$815 $777 
Valuation allowances for federal credit carryforwards(11)(5)
State NOL carryforwards— 1 
State tax credit carryforwards, net of federal detriment (a)
60 55 
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(57)(52)
(a)State tax credit carryforwards are net of federal detriment of $16 million and $15 million as of Dec. 31, 2024 and 2023, respectively.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $14 million as of Dec. 31, 2024 and 2023, respectively.
Federal carryforward periods expire between 2038 and 2044. State carryforward periods, not including those with indefinite carryforward periods, expire between 2025 and 2036.

Unrecognized Tax Benefits
Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s)Expiration
2014 - 2016March 2025
2021October 2025
Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. In 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agreed with the report and re-recognized the related benefit in 2023.
State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31, 2024, NSP-Minnesota’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
StateTax Year(s)Expiration
Minnesota2014-2016September 2025
Minnesota2020June 2025
There are currently no state income tax audits in progress.
Unrecognized tax benefit balance may include permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance may include temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.
Unrecognized tax benefits - permanent vs temporary:
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
Unrecognized tax benefit — Permanent tax positions$20 $18 
Unrecognized tax benefit — Temporary tax positions— — 
Total unrecognized tax benefit$20 $18 
Changes in unrecognized tax benefits:
(Millions of Dollars)202420232022
Balance at Jan. 1$18 $34 $26 
Additions based on tax positions related to the current year3 2 2 
Additions for tax positions of prior years— 1 6 
Reductions for tax positions of prior years(1)(18)— 
Reductions for tax positions related to settlements with taxing authorities— (1)— 
Balance at Dec. 31$20 $18 $34 
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
NOL and tax credit carryforwards$(17)$(18)

There exists approximately $20 million of noncurrent liabilities related to unrecognized tax benefits for which there is uncertainty about if or when these liabilities will significantly increase or decrease.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)202420232022
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1$1 $(3)$(2)
Interest (expense) benefit related to unrecognized tax benefits(1)4 (1)
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31$— $1 $(3)
No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2024, 2023 or 2022.
v3.25.0.1
Fair Value of Financial Assets and Liabilities
 12 Months Ended
Dec. 31, 2024
Fair Value Disclosures [Abstract]  
Fair Value Disclosures [Text Block]
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.
•Level 2 — Pricing inputs are other than actual trading prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.
Specific valuation methods include:
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments. FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $1.4 billion and $1.2 billion as of Dec. 31, 2024 and 2023, respectively, and unrealized losses were $49 million and $29 million as of Dec. 31, 2024 and 2023, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
Dec. 31, 2024
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$39 $39 $— $— $— $39 
Commingled funds703 — — — 1,025 1,025 
Debt securities866 — 832 14 — 846 
Equity securities522 1,583 1 — — 1,584 
Total$2,130 $1,622 $833 $14 $1,025 $3,494 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.
Dec. 31, 2023
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$41 $41 $— $— $— $41 
Commingled funds721 — — — 1,049 1,049 
Debt securities784 — 771 9 — 780 
Equity securities508 1,339 2 — — 1,341 
Total$2,054 $1,380 $773 $9 $1,049 $3,211 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.
For the years ended Dec. 31, 2024 and 2023, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2024:
Final Contractual Maturity
(Millions of Dollars)Due in 1 Year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 YearsTotal
Debt securities$7 $308 $269 $262 $846 
NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates and utility commodity prices.
Interest Rate Derivatives — NSP-Minnesota enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of Dec. 31, 2024, accumulated other comprehensive loss related to interest rate derivatives included immaterial of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2024, NSP-Minnesota had no unsettled interest rate swaps outstanding.
See Note 11 for the financial impact of qualifying interest rate cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.
Wholesale and Commodity Trading — NSP-Minnesota 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. NSP-Minnesota is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at Dec. 31, 2024 and 2023 for this purpose relate to FTR instruments administered by MISO. These instruments are intended to offset the impacts of transmission system congestion.
When NSP-Minnesota enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms. As of Dec. 31, 2024, NSP-Minnesota had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b)
Dec. 31, 2024Dec. 31, 2023
MWh of electricity31 38 
MMBtu of natural gas57 64 
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets. NSP-Minnesota often has significant concentrations of credit risk with particular entities or industries in its wholesale, trading and non-trading commodity activities.
As of Dec. 31, 2024, six of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $20 million or 22% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
One of the ten most significant counterparties, comprising $27 million or 29% of this credit exposure, were not rated by these external ratings agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade.
Three of these significant counterparties, comprising $43 million or 47% of this credit exposure, had credit quality less than investment grade, based on internal analysis.
Three of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2024 and 2023, there were $11 million and $12 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of Dec. 31, 2024 and 2023, there were approximately $63 million and $80 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2024 and 2023.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)Accumulated Other Comprehensive LossRegulatory (Assets) and Liabilities
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate$16 $— 
Total$16 $— 
Other derivative instruments
Electric commodity$— $(18)
Natural gas commodity— 2 
Total$— $(16)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate$(3)$— 
Total$(3)$— 
Other derivative instruments
Electric commodity$— $(48)
Natural gas commodity— (1)
Total$— $(49)
Year Ended Dec. 31, 2022
Other derivative instruments
Electric commodity$— $(7)
Total$— $(7)
Pre-Tax (Gains) Losses Reclassified into Income During the Period from:Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)Accumulated Other Comprehensive LossRegulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $(10)
(b)
Electric commodity— 21 
(c)
— 
Natural gas commodity— — (7)
(d)(e)
Total$— $21 $(17)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $(2)
(b)
Electric commodity— 45 
(c)
— 
Natural gas commodity— — (8)
(d)(e)
Total$— $45 $(10)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $17 
(b)
Electric commodity$— $1 
(c)
$— 
Natural gas commodity— 2 
(d)
(8)
(d)(e)
Total$— $3 $9 
(a)Recorded to interest charges.
(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value.
(d)Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2024, 2023 and 2022.
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2024Dec. 31, 2023
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Other derivative instruments:
Commodity trading$5 $20 $8 $33 $(22)$11 $7 $32 $32 $71 $(42)$29 
Electric commodity— — 23 23 (2)21 — — 23 23 (7)16 
Natural gas commodity— 4 — 4 — 4 — 5 — 5 — 5 
Total current derivative assets$5 $24 $31 $60 $(24)$36 $7 $37 $55 $99 $(49)$50 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$3 $33 $47 $83 $(16)$67 $7 $43 $45 $95 $(34)$61 
Total noncurrent derivative assets$3 $33 $47 $83 $(16)$67 $7 $43 $45 $95 $(34)$61 
Dec. 31, 2024Dec. 31, 2023
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate$— $— $— $— $— $— $— $7 $— $7 $— $7 
Other derivative instruments:
Commodity trading6 35 5 46 (22)24 6 60 5 71 (43)28 
Electric commodity— — 1 1 (1)— — — 7 7 (7)— 
Natural gas commodity— 1 — 1 — 1 — 3 — 3 — 3 
Total current derivative liabilities$6 $36 $6 $48 $(23)25 $6 $70 $12 $88 $(50)38 
PPAs (b)
6 6 
Current derivative instruments$31 $44 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$9 $30 $40 $79 $(18)$61 $14 $49 $37 $100 $(36)$64 
Total noncurrent derivative liabilities$9 $30 $40 $79 $(18)61 $14 $49 $37 $100 $(36)64 
PPAs (b)
16 22 
Noncurrent derivative instruments$77 $86 
(a)NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2024 and 2023, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2024 and 2023, derivative assets and liabilities include rights to reclaim cash collateral of $1 million and $3 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)NSP-Minnesota currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 commodity derivatives:
Year Ended Dec. 31
(Millions of Dollars)202420232022
Balance at Jan. 1$51 $107 $56 
Purchases (a)
72 98 157 
Settlements (a)
(61)(65)(195)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)
(9)15 91 
Net losses recognized as regulatory assets and liabilities (a)
(21)(104)(2)
Balance at Dec. 31$32 $51 $107 
(a)Relates primarily to FTR instruments administered by MISO.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the consolidated income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
20242023
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$7,857 $6,755 $7,330 $6,561 
Long-term debt - related parties166 99 — — 
Fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2024 and 2023, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
v3.25.0.1
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
Legal
NSP-Minnesota 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 NSP-Minnesota’s consolidated financial statements. Legal fees are generally expensed as incurred.
Rate Matters and Other
NSP-Minnesota is 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, the NSP-Minnesota recognized a customer refund of $47 million for replacement power incurred during the outage.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for NSP-Minnesota, 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. NSP-Minnesota may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota’s 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 NSP-Minnesota is alleged to have sent wastes to that site.
MGP, Landfill and Disposal Sites
NSP-Minnesota is investigating, remediating or performing post-closure actions at seven MGP, landfill or other disposal sites across its service territories.
NSP-Minnesota has recognized approximately $1 million of costs/liabilities for resolution of these issues, however, the final outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — NSP-Minnesota 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 may be required to perform additional groundwater investigations and/or perform corrective actions, typically beginning with an Assessment of Corrective Measures.
NSP-Minnesota expects to incur $6 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.
NSP-Minnesota 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 $60 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
NSP-Minnesota 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.
Federal 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.
NSP-Minnesota estimates capital expenditures of approximately $45 million may be required to comply with the requirements. NSP-Minnesota anticipates these costs will be recoverable through regulatory mechanisms.
Environmental Requirements — Air
Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations under the "Good Neighbor" provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, as well as other states outside of our service territory. The rule establishes an allowance trading program for NOx that will impact NSP-Minnesota’s fossil fuel-fired electric generating facilities. Applicable facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations.
While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, — AROs have been recorded for NSP-Minnesota’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 at Dec. 31, 2024 and 2023, respectively.
NSP-Minnesota’s AROs were as follows:
2024
(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 
Wind424 — — 15 (33)406 
Steam and other production77 61 (6)4 3 139 
Distribution17 — — 1 — 18 
Natural gas
Transmission and distribution32 — — 2 (1)33 
Other
Miscellaneous1 — — — — 1 
Total liability$2,658 $61 $(6)$128 $232 $3,073 
(a)Amounts incurred pertain to CCR coal ash regulations and Sherco Solar 1 being placed in service.
(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes in the nuclear AROs were driven by updated assumptions in the nuclear triennial filing coupled with discount rate and escalation rate changes. Wind, steam, and other production AROs were revised due to the results of 2024 dismantling studies.
2023
(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 
Wind416 10 — 15 (17)424 
Steam and other production75 — (1)3 — 77 
Distribution16 — — 1 — 17 
Natural gas
Transmission and distribution59 — — 2 (29)32 
Other
Miscellaneous1 — — — — 1 
Total liability$2,727 $10 $(1)$126 $(204)$2,658 
(a)Amounts incurred relate to the Northern Wind farm placed in service.
(b)In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2024. Therefore, an ARO has not been recorded for these facilities.
Nuclear Related
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.
Leases
NSP-Minnesota 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 if the arrangement is a finance lease.
ROU assets represent NSP-Minnesota's rights to use leased assets. The present value of future operating lease payments is recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of NSP-Minnesota’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted average of 4.7%). For currently existing asset classes, NSP-Minnesota has elected to utilize 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, 2024Dec. 31, 2023
PPAs$709 $709 
Other166 125 
Gross operating lease ROU assets875 834 
Accumulated amortization(482)(395)
Net operating lease ROU assets$393 $439 
Components of lease expense:
(Millions of Dollars)202420232022
Operating leases
PPA capacity payments$96 $100 $98 
Other operating leases (a)
15 13 9 
Total operating lease expense (b)
$111 $113 $107 
(a)Includes immaterial short-term lease expense for 2024, 2023 and 2022.
(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 leases as of Dec. 31, 2024:
(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
2025$101 $13 $114 
202689 13 102 
202772 13 85 
202840 13 53 
2029— 12 12 
Thereafter— 195 195 
Total minimum obligation302 259 561 
Interest component of obligation(22)(125)(147)
Present value of minimum obligation$280 $134 414 
Less current portion(97)
Noncurrent operating lease liabilities$317 
Weighted-average remaining lease term in years11.9
(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.
PPAs and Fuel Contracts
Non-Lease PPAs — NSP-Minnesota has 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 PPAs, accounted for as executory contracts with various expiration dates through 2041, contain minimum energy purchase commitments. Total energy payments on those contracts were $186 million, $185 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 $64 million, $62 million and $60 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 NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars)Capacity
Energy (a)
2025$32 $53 
202615 21 
202713 21 
20286 22 
20296 22 
Thereafter2 — 
Total (b)
$74 $139 
(a)Excludes contingent energy payments for renewable energy PPAs.
(b)Includes amounts allocated to NSP-Wisconsin through intercompany charges.
Fuel Contracts — NSP-Minnesota 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 in various years between 2025 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities delivered under these agreements.
Estimated minimum purchases for these contracts as of Dec. 31, 2024:
(Millions of Dollars)CoalNuclear fuelNatural gas
supply		Natural gas
storage and
transportation
2025$104 $168 $84 $141 
202640 62 — 140 
20274 133 — 108 
2028— 19 — 41 
2029— 67 — 21 
Thereafter— 49 — 29 
Total (a)
$148 $498 $84 $480 
(a)Includes amounts allocated to NSP-Wisconsin through interchange billings.
VIEs
Under certain PPAs, NSP-Minnesota purchases power from IPPs for which NSP-Minnesota is required to reimburse fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. NSP-Minnesota has determined that certain IPPs are VIEs, however NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
NSP-Minnesota evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. NSP-Minnesota concluded that these entities are not required to be consolidated in its consolidated financial statements because NSP-Minnesota does not have the power to direct the activities that most significantly impact the entities’ economic performance.
NSP-Minnesota had approximately 1,347 MW of capacity under long-term PPAs at both Dec. 31, 2024 and 2023, with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.
v3.25.0.1
Other Comprehensive Income
 12 Months Ended
Dec. 31, 2024
Stockholders' Equity Note [Abstract]  
Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
2024
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(18)$(2)$(20)
Other comprehensive income before reclassifications$12 $— $12 
Accumulated other comprehensive loss at Dec. 31$(6)$(2)$(8)
2023
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(16)$(2)$(18)
Other comprehensive loss before reclassifications$(3)$— $(3)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges
1 
(a)
— 1 
Net current period other comprehensive income(2)— (2)
Accumulated other comprehensive loss at Dec. 31$(18)$(2)$(20)
(a)Included in interest charges.
v3.25.0.1
Segments and Related Information
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Segment Information
NSP-Minnesota is a wholly owned subsidiary of Xcel Energy. NSP-Minnesota’s chief operating decision maker, the CEO of Xcel Energy, sets financial performance objectives and budgets, with separate targets for regulated electric utility and regulated natural gas utility net income.
The regulated electric utility and regulated natural gas utility segments are managed separately because of inherent differences between activities to serve electric customers and those required to serve natural gas customers, and as the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. The CEO assesses financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies.
NSP-Minnesota has the following reportable segments:
•Regulated Electric Utility — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Minnesota, North Dakota and South Dakota; each state’s regulated electric utility activities qualify as an operating segment, and is aggregated into NSP-Minnesota’s regulated electric utility segment. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas Utility — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Minnesota and North Dakota; each state’s regulated natural gas utility activities qualify as an operating segment, and is aggregated into NSP-Minnesota’s regulated natural gas utility segment.
Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments. As an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Other segment expenses, net, for the reportable segments includes conservation and DSM expenses, taxes (other than income taxes), other income (expense), net, intersegment expenses and AFUDC - equity.
Non-segment revenues include appliance repair and non-utility real estate activities and revenues associated with processing solid waste into RDF. Non-segment net income also includes costs associated with these activities.
Segment information and reconciliations to NSP-Minnesota’s consolidated operating revenues and net income:
2024
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues (a)
$5,099 $653 $5,752 
Intersegment revenue1 11 12 
Total segment revenues5,100 664 5,764 
Electric fuel and purchased power1,988 — 1,988 
Cost of natural gas sold and transported— 295 295 
O&M expenses1,181 104 1,285 
Depreciation and amortization1,025 80 1,105 
Other segment expenses, net301 53 354 
Interest charges and financing costs307 30 337 
Income tax (benefit) expense(390)25 (365)
Net income$688 $77 $765 
Total segment revenues$5,764 
Eliminate intersegment revenue(12)
Non-segment revenues15 
Consolidated operating revenues$5,767 
Total segment net income$765 
Non-segment net income28 
Consolidated net income$793 
(a)Regulated electric results include $460 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.
v3.25.0.1
Related Party Transactions
 12 Months Ended
Dec. 31, 2024
Related Party Transactions [Abstract]  
Related Party Transactions
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Minnesota. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Minnesota uses the services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy, Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.
See Note 5 for further information.
The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.
Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Millions of Dollars)202420232022
Operating revenues:
Electric$460 $493 $514 
Gas1 1 — 
Operating expenses:
Purchased power65 63 70 
Transmission expense151 142 132 
Other operating expenses — paid to Xcel Energy Services Inc.710 719 673 
Interest income5 1 1 
Interest expense2 5 1 
Accounts receivable and payable with affiliates at Dec. 31:
20242023
(Millions of Dollars)Accounts ReceivableAccounts PayableAccounts ReceivableAccounts Payable
NSP-Wisconsin$— $28 $9 $— 
PSCo— 7 5 — 
SPS— 2 — 4 
Other subsidiaries of Xcel Energy Inc.1 63 1 85 
$1 $100 $15 $89 
During 2024, Xcel Energy Inc. repurchased certain of NSP-Minnesota’s first mortgage bonds. For more information about these repurchases, see Note 5.
v3.25.0.1
Compensation Related Costs, Postemployment Benefits
 12 Months Ended
Dec. 31, 2024
Postemployment Benefits [Abstract]  
Postemployment Benefits Disclosure
In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.
In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.
In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.
In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, of which $32 million was attributable to NSP-Minnesota. Expenses relate to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.
No such activities occurred in 2024.
For further information on the estimated obligations for future health plan subsidies and other medical benefits, see Note 9 to the consolidated financial statements.
v3.25.0.1
Schedule II, Valuation and Qualifying Accounts
 12 Months Ended
Dec. 31, 2024
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]  
Schedule II, Valuation and Qualifying Accounts
SCHEDULE II
NSP-Minnesota and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
Allowance for bad debts
(Millions of Dollars)202420232022
Balance at Jan. 1$48 $46 $45 
Additions charged to costs and expenses21 30 21 
Additions charged to other accounts (a)
7 6 6 
Deductions from reserves (b)
(34)(34)(26)
Balance at Dec. 31$42 $48 $46 
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
v3.25.0.1
Pay vs Performance Disclosure - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Pay vs Performance Disclosure      
Net income $ 793 $ 707 $ 675
v3.25.0.1
Insider Trading Arrangements
 12 Months Ended
Dec. 31, 2024
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.25.0.1
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.0.1
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
NSP-Minnesota is a wholly owned subsidiary of Xcel Energy. As such, its cybersecurity processes are maintained by Xcel Energy management and governed by its Board of Directors.
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.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] 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.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
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 Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] 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.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]
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.
Cybersecurity Risk Role of Management [Text Block]
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.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
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.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] 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.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]
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.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.0.1
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Business and System of Accounts
General — NSP-Minnesota is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.
NSP-Minnesota’s consolidated financial statements are presented in accordance with GAAP. All of NSP-Minnesota’s 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.
Principles of Consolidation
NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.
Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Minnesota’s proportionate share of operating costs associated with these facilities is included in its consolidated statements of income.
Subsequent Events
NSP-Minnesota 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
Use of Estimates — NSP-Minnesota 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 and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting
Regulatory Accounting — NSP-Minnesota accounts 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, NSP-Minnesota 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 NSP-Minnesota’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes
Income Taxes — NSP-Minnesota 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 NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its 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. NSP-Minnesota 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.
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 NSP-Minnesota tax elections. For tax credits otherwise eligible to be recognized when earned, NSP-Minnesota 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 regulatory mechanisms.
NSP-Minnesota 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, including NSP-Minnesota 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
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 3.9% for 2024, 3.7% for 2023 and 4.0% for 2022.
See Note 3 for further information.
Asset Retirement Obligations
AROs — NSP-Minnesota 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 10 for further information.
Nuclear Decommissioning
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 8 and 10 for further information.
Benefit Plans and Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits — NSP-Minnesota 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 9 for further information.
Environmental Costs
Environmental Costs — Environmental costs are recorded when it is probable NSP-Minnesota 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 NSP-Minnesota’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 10 for further information.
Revenue From Contracts With Customers
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Minnesota 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.
NSP-Minnesota recognizes 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 RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.
NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
See Note 6 for further information.
Cash and Cash Equivalents
Cash and Cash Equivalents — NSP-Minnesota 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 and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota 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 $42 million and $48 million, respectively.
Inventory
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, 2023
Inventories
Materials and supplies$234 $219 
Fuel81 105 
Natural gas24 32 
Total inventories$339 $356 
Fair Value Measurements
Fair Value Measurements — NSP-Minnesota 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 8 and 9 for further information.
Derivative Instruments
Derivative Instruments — NSP-Minnesota 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 — NSP-Minnesota 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 8 for further information.
Commodity Trading Operations
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 NSP-Minnesota’s 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 8 for further information.
AFUDC 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 NSP-Minnesota’s rate base.
Alternative Revenue Programs
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.
Emission Allowances
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
Nuclear Refueling Outage Costs — NSP-Minnesota uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.
Renewable Energy Credits
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. An inventory accounting model is used to account for RECs.
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.
v3.25.0.1
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2024
Balance Sheet Related Disclosures [Abstract]  
Schedule of Utility Inventory [Table Text Block]
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, 2023
Inventories
Materials and supplies$234 $219 
Fuel81 105 
Natural gas24 32 
Total inventories$339 $356 
v3.25.0.1
Property Plant and Equipment (Tables)
 12 Months Ended
Dec. 31, 2024
Property, Plant and Equipment [Abstract]  
Public Utility Property, Plant, and Equipment
Major classes of property, plant and equipment
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
Property, plant and equipment, net
Electric plant$23,218 $21,206 
Natural gas plant2,472 2,256 
Common and other property1,450 1,301 
Plant to be retired (a)
554 604 
CWIP1,522 1,085 
Total property, plant and equipment29,216 26,452 
Less accumulated depreciation(8,753)(8,044)
Nuclear fuel3,491 3,337 
Less accumulated amortization(3,094)(2,988)
Property, plant and equipment, net$20,860 $18,757 
(a)Amounts include Sherco 1 and 3 and A.S. King. Balance is presented net of accumulated depreciation.
Joint Ownership of Generation and Transmission Facilities
Jointly owned assets as of Dec. 31, 2024:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
Electric 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 (a)
$1,745 $798 
(a)Projects additionally include $10 million in CWIP.
NSPM separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing.
Schedule of Jointly Owned Utility Plants
Joint Ownership of Generation and Transmission Facilities
Jointly owned assets as of Dec. 31, 2024:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
Electric 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 (a)
$1,745 $798 
(a)Projects additionally include $10 million in CWIP.
v3.25.0.1
Regulatory Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets
Components of regulatory assets:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2024Dec. 31, 2023
Regulatory AssetsCurrentNoncurrentCurrentNoncurrent
Pension and retiree medical obligations9 Various$21 $339 $18 $340 
Recoverable deferred taxes on AFUDCPlant lives— 137 — 127 
Excess deferred taxes — TCJA
7Various8 87 8 96 
MISO capacity revenue tracker
One to two years
63 45 36 26 
Prairie Island extended power uprate
10 years
4 34 4 38 
Benson biomass PPA termination and asset purchase
Four years
10 26 10 36 
Deferred purchased natural gas
One to two years
51 25 16 58 
Sales true-up and revenue decoupling
One to two years
60 23 7 2 
Nuclear refueling outage costs1
One to two years
51 20 43 19 
Contract valuation adjustments (a)
1, 8Term of related contract7 16 9 22 
Purchased power contracts costsTerm of related contract1 16 1 20 
Conservation programs (b)
1
One to two years
8 15 6 19 
Renewable resources and environmental initiatives
Less than one year
34 — 38 — 
Gas pipeline inspection and remediation costs
Less than one year
30 — 37 — 
Other Various16 30 17 34 
Total regulatory assets$364 $813 $250 $837 
(a)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Regulatory Liabilities
Components of regulatory liabilities:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2024Dec. 31, 2023
Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Deferred income tax adjustments and TCJA refunds (a)
7Various$5 $1,105 $5 $1,157 
Plant removal costs1, 10Various— 815 — 741 
Net AROs (b)
Various— 161 — 90 
Renewable resources and environmental initiativesVarious16 38 9 27 
Deferred natural gas and electric energy/fuel costs (c)
One to two years
348 12 143 — 
Conservation programs
Less than one year
41 — 27 — 
Contract valuation adjustments (d)
1, 8
Less than one year
21 — 16 — 
Other Various112 24 100 82 
Total regulatory liabilities (e)
$543 $2,155 $300 $2,097 
(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.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes Nuclear PTCs.
(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
(e)Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities.
v3.25.0.1
Borrowings and Other Financing Instruments (Tables)
 12 Months Ended
Dec. 31, 2024
Debt Disclosure [Abstract]  
Money Pool [Table Text Block]
Money pool borrowings:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31
202420232022
Borrowing limit$250 $250 $250 $250 
Amount outstanding at period end— — — — 
Average amount outstanding31 10 17 — 
Maximum amount outstanding139 139 135 4 
Weighted average interest rate, computed on a daily basis4.62 %4.82 %4.97 %3.87 %
Weighted average interest rate at period endN/AN/AN/AN/A
Short Term Debt Commercial paper outstanding:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2024Year Ended Dec. 31
202420232022
Borrowing limit$700 $700 $700 $700 
Amount outstanding at period end195 195 165 207 
Average amount outstanding24 54 92 21 
Maximum amount outstanding215 400 441 290 
Weighted average interest rate, computed on a daily basis4.62 %5.39 %4.99 %4.14 %
Weighted average interest rate at end of period4.63 4.63 5.47 4.64 
Schedule of Debt To Total Capitalization Ratio
Features of NSP-Minnesota’s credit facility:
Debt-to-Total Capitalization Ratio (a)
Amount Facility May Be Increased (millions of dollars)
Additional Periods for Which a One-Year Extension May Be Requested (b)
20242023
47.0 %47.7 %$150 2 
(a)The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b)All extension requests are subject to majority bank group approval 		[1],[2]
Credit Facilities
NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2024 (in millions of dollars):
Credit Facility (a)
Drawn (b)
Available
$700 $207 $493 
(a)This credit facility matures in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
 [3]
Schedule of Long-Term Debt
Long term debt obligations for NSP-Minnesota as of Dec. 31 (in millions of dollars):
Financing InstrumentInterest RateMaturity Date20242023
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 bonds (a)
2.60 June 1, 2051700 700 
First mortgage bonds3.20 April 1, 2052425 425 
First mortgage bonds4.50 June 1, 2052500 500 
First mortgage bonds (b)
5.10 May 15, 2053800 800 
First mortgage bonds (c)
5.40 March 15, 2054700 — 
Other long-term debt2 2 
Long-term debt — related parties principal amount outstanding (a)
2.60 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)During 2024, Xcel Energy Inc. purchased a portion of these NSP-Minnesota first mortgage bonds for $105 million. Interest expense related to these repurchased bonds was immaterial for the year ended Dec. 31, 2024.
(b)2023 financing.
(c)2024 financing.
 [4],[5]
Schedule of Maturities of Long-term Debt
Maturities of long-term debt are as follows:
(Millions of Dollars)
2025$250 
2026— 
2027— 
2028150 
2029— 
Dividend Payment Restrictions
Requirements and actuals as of Dec. 31, 2024:
Equity to Total Capitalization Ratio
Required Range 		Equity to Total Capitalization Ratio Actual
LowHigh2024
47.6 %58.2 %53.0 %
Unrestricted Retained EarningsTotal CapitalizationLimit on Total Capitalization
$1,809  million$17,490  million$17,800  million
[1] All extension requests are subject to majority bank group approval.
[2] The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
[3] Includes outstanding commercial paper and letters of credit.
[4] 2023 financing.
[5] 2024 financing.
v3.25.0.1
Revenues Revenues (Tables)
 12 Months Ended
Dec. 31, 2024
Revenue from Contract with Customer [Abstract]  
Disaggregation of Revenue
Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Minnesota’s operating revenues consisted of the following:
Year Ended Dec. 31, 2024
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,496 $328 $7 $1,831 
C&I2,191 221 — 2,412 
Other36 — 8 44 
Total retail3,723 549 15 4,287 
Wholesale319 — — 319 
Transmission262 — — 262 
Interchange and other446 31 — 477 
Total revenue from contracts with customers4,750 580 15 5,345 
Alternative revenue and other349 73 — 422 
Total revenues$5,099 $653 $15 $5,767 
Year Ended Dec. 31, 2023
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,524 $368 $41 $1,933 
C&I2,298 309 — 2,607 
Other34 — 7 41 
Total retail3,856 677 48 4,581 
Wholesale354 — — 354 
Transmission263 — — 263 
Interchange and other493 18 — 511 
Total revenue from contracts with customers4,966 695 48 5,709 
Alternative revenue and other275 59 — 334 
Total revenues$5,241 $754 $48 $6,043 
Year Ended Dec. 31, 2022
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$1,463 $510 $38 $2,011 
C&I2,376 433 — 2,809 
Other38 — 7 45 
Total retail3,877 943 45 4,865 
Wholesale668 — — 668 
Transmission287 — — 287 
Interchange and other529 19 — 548 
Total revenue from contracts with customers5,361 962 45 6,368 
Alternative revenue and other256 60 — 316 
Total revenues$5,617 $1,022 $45 $6,684 
v3.25.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2024
Income Tax Disclosure [Abstract]  
Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block] NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s)Expiration
2014 - 2016March 2025
2021October 2025
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefits - permanent vs temporary:
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
Unrecognized tax benefit — Permanent tax positions$20 $18 
Unrecognized tax benefit — Temporary tax positions— — 
Total unrecognized tax benefit$20 $18 
Changes in unrecognized tax benefits:
(Millions of Dollars)202420232022
Balance at Jan. 1$18 $34 $26 
Additions based on tax positions related to the current year3 2 2 
Additions for tax positions of prior years— 1 6 
Reductions for tax positions of prior years(1)(18)— 
Reductions for tax positions related to settlements with taxing authorities— (1)— 
Balance at Dec. 31$20 $18 $34 
Tax Benefits Associated with NOL and Tax Credit Carryforwards
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
NOL and tax credit carryforwards$(17)$(18)
Interest Payable related to Unrecognized Tax Benefits
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)202420232022
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1$1 $(3)$(2)
Interest (expense) benefit related to unrecognized tax benefits(1)4 (1)
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31$— $1 $(3)
NOL and Tax Credit Carryforwards NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)20242023
Federal tax credit carryforwards$815 $777 
Valuation allowances for federal credit carryforwards(11)(5)
State NOL carryforwards— 1 
State tax credit carryforwards, net of federal detriment (a)
60 55 
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(57)(52)
(a)State tax credit carryforwards are net of federal detriment of $16 million and $15 million as of Dec. 31, 2024 and 2023, respectively.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $14 million as of Dec. 31, 2024 and 2023, respectively.
Schedule of Effective Income Tax Rate Reconciliation
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31:
202420232022
Federal statutory rate21.0 %21.0 %21.0 %
State income tax on pretax income, net of federal tax effect7.1 7.0 7.0 
Increases (decreases) in tax from:
PTCs (a)
(99.4)(39.5)(39.6)
Plant regulatory differences (b)
(9.2)(5.7)(6.7)
Other tax credits, net NOL & tax credit allowances(1.9)(1.3)(1.3)
Other, net0.9 0.3 (0.3)
Effective income tax rate(81.5)%(18.2)%(19.9)%
(a)Wind, Solar, and Nuclear PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings. Nuclear PTCs, newly available in 2024, resulted in benefits of 39.5% to the ETR for the year ended Dec. 31, 2024.
(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
Schedule of Components of Income Tax Expense (Benefit)
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)202420232022
Current federal tax (benefit) expense $(149)$(154)$70 
Current state tax (benefit) expense(25)3 26 
Current change in unrecognized tax expense (benefit)3 (21)8 
Deferred federal tax (benefit) expense(244)5 (237)
Deferred state tax expense61 51 23 
Deferred change in unrecognized tax (benefit) expense(1)8 — 
Deferred ITCs(1)(1)(2)
Total income tax benefit$(356)$(109)$(112)
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)202420232022
Deferred tax expense (benefit) excluding items below$246 $326 (283)
Adjustments to deferred income taxes for tax credit cash transfers (a)
(325)(150)— 
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities     
(99)(114)70 
Tax (expense) benefit allocated to other comprehensive income and other(6)2 (1)
Deferred tax (benefit) expense$(184)$64 $(214)
(a)Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.
Schedule of Deferred Tax Assets and Liabilities
Components of the net deferred tax liability as of Dec. 31:
(Millions of Dollars)2024
2023 (a)
Deferred tax liabilities:
Differences between book and tax bases of property$3,150 $2,938 
Regulatory assets234 173 
Operating lease assets115 129 
Pension expense67 64 
Deferred fuel costs21 20 
Other21 9 
Total deferred tax liabilities$3,608 $3,333 
Deferred tax assets:
Tax credit carryforward$875 $832 
Regulatory liabilities358 306 
Operating lease liabilities115 129 
Rate refund10 59 
NOL and tax credit valuation allowances(68)(57)
Other employee benefits28 31 
Deferred ITCs4 4 
Other48 37 
Total deferred tax assets$1,370 $1,341 
Net deferred tax liability$2,238 $1,992 
(a)Prior periods have been reclassified to conform to current year presentation.
State Statute of Limitations Applicable to Open Tax Years NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31, 2024, NSP-Minnesota’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
StateTax Year(s)Expiration
Minnesota2014-2016September 2025
Minnesota2020June 2025
v3.25.0.1
Fair Value of Financial Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2024
Fair Value Disclosures [Abstract]  
Cost and Fair Value of Nuclear Decommissioning Fund Investments
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
Dec. 31, 2024
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$39 $39 $— $— $— $39 
Commingled funds703 — — — 1,025 1,025 
Debt securities866 — 832 14 — 846 
Equity securities522 1,583 1 — — 1,584 
Total$2,130 $1,622 $833 $14 $1,025 $3,494 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.
Dec. 31, 2023
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$41 $41 $— $— $— $41 
Commingled funds721 — — — 1,049 1,049 
Debt securities784 — 771 9 — 780 
Equity securities508 1,339 2 — — 1,341 
Total$2,054 $1,380 $773 $9 $1,049 $3,211 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2024:
Final Contractual Maturity
(Millions of Dollars)Due in 1 Year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 YearsTotal
Debt securities$7 $308 $269 $262 $846 
Gross Notional Amounts of Commodity Forwards, Options, and FTRs
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b)
Dec. 31, 2024Dec. 31, 2023
MWh of electricity31 38 
MMBtu of natural gas57 64 
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income
Impact of derivative activity:
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)Accumulated Other Comprehensive LossRegulatory (Assets) and Liabilities
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate$16 $— 
Total$16 $— 
Other derivative instruments
Electric commodity$— $(18)
Natural gas commodity— 2 
Total$— $(16)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate$(3)$— 
Total$(3)$— 
Other derivative instruments
Electric commodity$— $(48)
Natural gas commodity— (1)
Total$— $(49)
Year Ended Dec. 31, 2022
Other derivative instruments
Electric commodity$— $(7)
Total$— $(7)
Pre-Tax (Gains) Losses Reclassified into Income During the Period from:Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)Accumulated Other Comprehensive LossRegulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $(10)
(b)
Electric commodity— 21 
(c)
— 
Natural gas commodity— — (7)
(d)(e)
Total$— $21 $(17)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $(2)
(b)
Electric commodity— 45 
(c)
— 
Natural gas commodity— — (8)
(d)(e)
Total$— $45 $(10)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments
Commodity trading$— $— $17 
(b)
Electric commodity$— $1 
(c)
$— 
Natural gas commodity— 2 
(d)
(8)
(d)(e)
Total$— $3 $9 
(a)Recorded to interest charges.
(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value.
(d)Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2024, 2023 and 2022.
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2024Dec. 31, 2023
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Other derivative instruments:
Commodity trading$5 $20 $8 $33 $(22)$11 $7 $32 $32 $71 $(42)$29 
Electric commodity— — 23 23 (2)21 — — 23 23 (7)16 
Natural gas commodity— 4 — 4 — 4 — 5 — 5 — 5 
Total current derivative assets$5 $24 $31 $60 $(24)$36 $7 $37 $55 $99 $(49)$50 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$3 $33 $47 $83 $(16)$67 $7 $43 $45 $95 $(34)$61 
Total noncurrent derivative assets$3 $33 $47 $83 $(16)$67 $7 $43 $45 $95 $(34)$61 
Dec. 31, 2024Dec. 31, 2023
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate$— $— $— $— $— $— $— $7 $— $7 $— $7 
Other derivative instruments:
Commodity trading6 35 5 46 (22)24 6 60 5 71 (43)28 
Electric commodity— — 1 1 (1)— — — 7 7 (7)— 
Natural gas commodity— 1 — 1 — 1 — 3 — 3 — 3 
Total current derivative liabilities$6 $36 $6 $48 $(23)25 $6 $70 $12 $88 $(50)38 
PPAs (b)
6 6 
Current derivative instruments$31 $44 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$9 $30 $40 $79 $(18)$61 $14 $49 $37 $100 $(36)$64 
Total noncurrent derivative liabilities$9 $30 $40 $79 $(18)61 $14 $49 $37 $100 $(36)64 
PPAs (b)
16 22 
Noncurrent derivative instruments$77 $86 
(a)NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2024 and 2023, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2024 and 2023, derivative assets and liabilities include rights to reclaim cash collateral of $1 million and $3 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)NSP-Minnesota currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 Commodity Derivatives
Changes in Level 3 commodity derivatives:
Year Ended Dec. 31
(Millions of Dollars)202420232022
Balance at Jan. 1$51 $107 $56 
Purchases (a)
72 98 157 
Settlements (a)
(61)(65)(195)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)
(9)15 91 
Net losses recognized as regulatory assets and liabilities (a)
(21)(104)(2)
Balance at Dec. 31$32 $51 $107 
(a)Relates primarily to FTR instruments administered by MISO.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the consolidated income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Carrying Amount and Fair Value of Long-term Debt
20242023
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$7,857 $6,755 $7,330 $6,561 
Long-term debt - related parties166 99 — — 
v3.25.0.1
Benefit Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2024
Benefit Plans and Other Postretirement Benefits [Abstract]  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2024202320242023
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss$289 $321 $14 $15 
Total$289 $321 $14 $15 
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets$14 $11 $— $— 
Noncurrent regulatory assets275 310 13 14 
Net-of-tax accumulated other comprehensive income— — 1 1 
Total$289 $321 $14 $15 
Measurement dateDec 31, 2024Dec 31, 2023Dec 31, 2024Dec 31, 2023
Projected Benefit Payments for the Pension and Postretirement Benefit Plans
Projected Benefit Payments
NSP-Minnesota’s projected benefit payments:
(Millions of Dollars)Projected
Pension Benefit
Payments
Net Projected
Postretirement Health Care
Benefit Payments (a)
2025$63 $5 
2026$59 $5 
202758 4 
202856 4 
202957 4 
2030-2034269 15 
(a)Amount is reported net of expected Medicare Part D subsidies, which are immaterial.
Voluntary Retirement Program, Significant Assumptions to Measure Benefit Obligation
Significant Assumptions to Measure Benefit Obligations:20242023
Discount rate for year-end valuation5.00 %5.50 %
Mortality tablePRI-2012PRI-2012
Health care costs trend rate7.00 %7.00 %
Ultimate trend assumption4.50 %N/A
Years until ultimate trend is reached9N/A
Pension Plan  
Benefit Plans and Other Postretirement Benefits [Abstract]  
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2024202320242023
Change in Benefit Obligation:
Obligation at Jan. 1$660 $657 $42 $48 
Service cost22 21 1 — 
Interest cost34 36 2 3 
Plan amendments— (1)— — 
Actuarial (gain) loss(22)30 1 (2)
Benefit payments(82)(83)(5)(7)
Obligation at Dec. 31$612 $660 $41 $42 
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1$562 $570 $3 $5 
Actual return on plan assets7 52 — — 
Employer contributions41 23 4 5 
Benefit payments(82)(83)(5)(7)
Fair value of plan assets at Dec. 31$528 $562 $2 $3 
Funded status of plans at Dec. 31$(84)$(98)$(39)$(39)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Current liabilities$— $— $(3)$(2)
Noncurrent liabilities(84)(98)(36)(37)
Net amounts recognized$(84)$(98)$(39)$(39)
    
Pension BenefitsPostretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:2024202320242023
Discount rate for year-end valuation5.88 %5.49 %5.88 %5.54 %
Expected average long-term increase in compensation level4.25 %4.25 %N/AN/A
Mortality tablePRI-2012PRI-2012PRI-2012PRI-2012
Health care costs trend rate — initial: Pre-65N/AN/A7.00 %6.50 %
Health care costs trend rate — initial: Post-65N/AN/A7.50 %5.50 %
Ultimate trend assumption — initial: Pre-65N/AN/A4.50 %4.50 %
Ultimate trend assumption — initial: Post-65N/AN/A4.50 %4.50 %
Years until ultimate trend is reachedN/AN/A96
Components of Net Periodic Benefit Costs
Pension BenefitsPostretirement Benefits
(Millions of Dollars)202420232022202420232022
Service cost$22 $21 $27 $1 $— $— 
Interest cost34 36 25 2 3 2 
Expected return on plan assets(46)(46)(48)— — — 
Amortization of prior service cost— — — — (1)(3)
Amortization of net loss13 11 24 — — 1 
Settlement charge (a)
37 — 38 — — — 
Net periodic pension cost60 22 66 3 2 — 
Effects of regulation(30)16 (32)— — — 
Net benefit cost recognized for financial reporting$30 $38 $34 $3 $2 $— 
Significant Assumptions Used to Measure Costs:
Discount rate5.49 %5.80 %3.08 %5.54 %5.80 %3.09 %
Expected average long-term increase in compensation level4.25 4.25 3.75 — — — 
Expected average long-term rate of return on assets7.25 7.25 6.60 5.00 5.00 4.10 
(a)A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024 and 2022, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $37 million and $38 million, respectively, which was not recognized in earnings due to the effects of regulation. There were no settlement charges recorded for the qualified pension plans in 2023.
Target Asset Allocations and Plan Assets Measured at Fair Value
For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value:
Dec. 31, 2024 (a)
Dec. 31, 2023 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$24 $— $— $— $24 $46 $— $— $— $46 
Commingled funds— — — 373 373 110 — — 265 375 
Debt securities— 123 1 — 124 — 127 1 — 128 
Equity securities6 — — — 6 8 — — — 8 
Other— 1 — — 1 — 5 — — 5 
Total$30 $124 $1 $373 $528 $164 $132 $1 $265 $562 
(a)See Note 8 for further information regarding fair value measurement inputs and methods.
For each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2024 (a)
Dec. 31, 2023 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Commingled funds$— $— $— $1 $1 $— $— $— $1 $1 
Debt securities— 1 — — 1 — 2 — — 2 
Total$— $1 $— $1 $2 $— $2 $— $1 $3 
(a)See Note 8 for further information on fair value measurement inputs and methods.
Immaterial assets were transferred in or out of Level 3 for 2024. No assets were transferred in or out of Level 3 for 2023.
Postretirement Benefits Plan  
Benefit Plans and Other Postretirement Benefits [Abstract]  
Target Asset Allocations and Plan Assets Measured at Fair Value
Targeted asset allocations:
Pension BenefitsPostretirement Benefits
2024202320242023
Long-duration fixed income and interest rate swap securities38 %38 %— %— %
Domestic and international equity securities31 31 25 9 
Alternative investments20 20 11 13 
Short-to-intermediate fixed income securities9 9 61 77 
Cash2 2 3 1 
Total100 %100 %100 %100 %
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
v3.25.0.1
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]  
Asset Retirement Obligations
NSP-Minnesota’s AROs were as follows:
2024
(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 
Wind424 — — 15 (33)406 
Steam and other production77 61 (6)4 3 139 
Distribution17 — — 1 — 18 
Natural gas
Transmission and distribution32 — — 2 (1)33 
Other
Miscellaneous1 — — — — 1 
Total liability$2,658 $61 $(6)$128 $232 $3,073 
(a)Amounts incurred pertain to CCR coal ash regulations and Sherco Solar 1 being placed in service.
(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes in the nuclear AROs were driven by updated assumptions in the nuclear triennial filing coupled with discount rate and escalation rate changes. Wind, steam, and other production AROs were revised due to the results of 2024 dismantling studies.
2023
(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 
Wind416 10 — 15 (17)424 
Steam and other production75 — (1)3 — 77 
Distribution16 — — 1 — 17 
Natural gas
Transmission and distribution59 — — 2 (29)32 
Other
Miscellaneous1 — — — — 1 
Total liability$2,727 $10 $(1)$126 $(204)$2,658 
(a)Amounts incurred relate to the Northern Wind farm placed in service.
(b)In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.
Assets and Liabilities, Lessee [Table Text Block]
Operating lease ROU assets:
(Millions of Dollars)Dec. 31, 2024Dec. 31, 2023
PPAs$709 $709 
Other166 125 
Gross operating lease ROU assets875 834 
Accumulated amortization(482)(395)
Net operating lease ROU assets$393 $439 
Lease, Cost [Table Text Block]
Components of lease expense:
(Millions of Dollars)202420232022
Operating leases
PPA capacity payments$96 $100 $98 
Other operating leases (a)
15 13 9 
Total operating lease expense (b)
$111 $113 $107 
(a)Includes immaterial short-term lease expense for 2024, 2023 and 2022.
(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.
Lessee, Operating Lease, Liability, Maturity [Table Text Block]
Commitments under operating leases as of Dec. 31, 2024:
(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
2025$101 $13 $114 
202689 13 102 
202772 13 85 
202840 13 53 
2029— 12 12 
Thereafter— 195 195 
Total minimum obligation302 259 561 
Interest component of obligation(22)(125)(147)
Present value of minimum obligation$280 $134 414 
Less current portion(97)
Noncurrent operating lease liabilities$317 
Weighted-average remaining lease term in years11.9
(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.
Estimated Minimum Purchases Under Fuel Contracts
Estimated minimum purchases for these contracts as of Dec. 31, 2024:
(Millions of Dollars)CoalNuclear fuelNatural gas
supply		Natural gas
storage and
transportation
2025$104 $168 $84 $141 
202640 62 — 140 
20274 133 — 108 
2028— 19 — 41 
2029— 67 — 21 
Thereafter— 49 — 29 
Total (a)
$148 $498 $84 $480 
(a)Includes amounts allocated to NSP-Wisconsin through interchange billings.
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements
At Dec. 31, 2024, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars)Capacity
Energy (a)
2025$32 $53 
202615 21 
202713 21 
20286 22 
20296 22 
Thereafter2 — 
Total (b)
$74 $139 
(a)Excludes contingent energy payments for renewable energy PPAs.
(b)Includes amounts allocated to NSP-Wisconsin through intercompany charges.
v3.25.0.1
Other Comprehensive Income (Tables)
 12 Months Ended
Dec. 31, 2024
Stockholders' Equity Note [Abstract]  
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
2024
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(18)$(2)$(20)
Other comprehensive income before reclassifications$12 $— $12 
Accumulated other comprehensive loss at Dec. 31$(6)$(2)$(8)
2023
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(16)$(2)$(18)
Other comprehensive loss before reclassifications$(3)$— $(3)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges
1 
(a)
— 1 
Net current period other comprehensive income(2)— (2)
Accumulated other comprehensive loss at Dec. 31$(18)$(2)$(20)
(a)Included in interest charges.
v3.25.0.1
Segments and Related Information (Tables)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting [Abstract]      
Results from Operations by Reportable Segment
2024
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues (a)
$5,099 $653 $5,752 
Intersegment revenue1 11 12 
Total segment revenues5,100 664 5,764 
Electric fuel and purchased power1,988 — 1,988 
Cost of natural gas sold and transported— 295 295 
O&M expenses1,181 104 1,285 
Depreciation and amortization1,025 80 1,105 
Other segment expenses, net301 53 354 
Interest charges and financing costs307 30 337 
Income tax (benefit) expense(390)25 (365)
Net income$688 $77 $765 
Total segment revenues$5,764 
Eliminate intersegment revenue(12)
Non-segment revenues15 
Consolidated operating revenues$5,767 
Total segment net income$765 
Non-segment net income28 
Consolidated net income$793 
(a)Regulated electric results include $460 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.
2023
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues (a)
$5,241 $754 $5,995 
Intersegment revenues1 2 3 
Total segment revenues5,242 756 5,998 
Electric fuel and purchased power2,069 — 2,069 
Cost of natural gas sold and transported— 466 466 
O&M expenses1,153 98 1,251 
Depreciation and amortization909 71 980 
Other segment expenses, net (b)
312 47 359 
Interest charges and financing costs278 26 304 
Income tax (benefit) expense(127)10 (117)
Net income$648 $38 $686 
Total segment revenues$5,998 
Eliminate intersegment revenue(3)
Non-segment revenues48 
Consolidated operating revenues$6,043 
Total segment net income$686 
Non-segment net income21 
Consolidated net income$707 
(a)Regulated electric results include $493 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.
(b)Other segment expenses, net, for 2023 additionally includes workforce reduction expenses.
2022
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues (a)
$5,617 $1,022 $6,639 
Intersegment revenues1 2 3 
Total segment revenues5,618 1,024 6,642 
Electric fuel and purchased power2,416 — 2,416 
Cost of natural gas sold and transported— 741 741 
O&M expenses1,126 94 1,220 
Depreciation and amortization953 60 1,013 
Other segment expenses, net
367 48 415 
Interest charges and financing costs257 22 279 
Income tax (benefit) expense(127)14 (113)
Net income$626 $45 $671 
Total segment revenues$6,642 
Eliminate intersegment revenue(3)
Non-segment revenues45 
Consolidated operating revenues$6,684 
Total segment net income$671 
Non-segment net income4 
Consolidated net income$675 
(a)Regulated electric results include $514 million of affiliate revenues. See Note 13 for further information.
v3.25.0.1
Related Party Transactions (Tables)
 12 Months Ended
Dec. 31, 2024
Related Party Transactions [Abstract]  
Related Party Transactions
Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Millions of Dollars)202420232022
Operating revenues:
Electric$460 $493 $514 
Gas1 1 — 
Operating expenses:
Purchased power65 63 70 
Transmission expense151 142 132 
Other operating expenses — paid to Xcel Energy Services Inc.710 719 673 
Interest income5 1 1 
Interest expense2 5 1 
Accounts receivable and payable with affiliates at Dec. 31:
20242023
(Millions of Dollars)Accounts ReceivableAccounts PayableAccounts ReceivableAccounts Payable
NSP-Wisconsin$— $28 $9 $— 
PSCo— 7 5 — 
SPS— 2 — 4 
Other subsidiaries of Xcel Energy Inc.1 63 1 85 
$1 $100 $15 $89 
v3.25.0.1
Summary of Significant Accounting Policies (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Property, Plant and Equipment [Abstract]      
Depreciation expense expressed as a percentage of average depreciable property 3.90% 3.70% 4.00%
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract]      
Allowance for bad debts $ 42 $ 48  
Alternative Revenue Programs [Abstract]      
maximum number of months following annual period 24 months    
Public Utilities, Inventory [Line Items]      
Public Utilities, Inventory $ 339 356  
maturity period 3 months    
maximum number of months following annual period 24 months    
Studies time periods 3 years    
Supplies      
Public Utilities, Inventory [Line Items]      
Public Utilities, Inventory $ 234 219  
Public Utilities, Inventory, Fuel      
Public Utilities, Inventory [Line Items]      
Public Utilities, Inventory 81 105  
Public Utilities, Inventory, Natural Gas      
Public Utilities, Inventory [Line Items]      
Public Utilities, Inventory $ 24 $ 32  
v3.25.0.1
Property Plant and Equipment (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Property, Plant and Equipment [Line Items]    
Property, plant and equipment $ 29,216 $ 26,452
Accumulated depreciation and amortization 8,753 8,044
Property, Plant and Equipment, Net 20,860 18,757
Property, Plant and Equipment, Gross, Including Nuclear Fuel 3,491 3,337
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment, Nuclear Fuel (3,094) (2,988)
Electric plant    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 23,218 21,206
Natural gas plant    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 2,472 2,256
Common and other property    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 1,450 1,301
Plant to be Retired [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment [1] 554 604
CWIP    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment $ 1,522 $ 1,085
[1] Amounts include Sherco 1 and 3 and A.S. King. Balance is presented net of accumulated depreciation.
v3.25.0.1
Property Plant and Equipment Property Plant and Equipment Joint Ownership (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 1,745 [1]
Accumulated Depreciation 798 [1]
CWIP 10
Electric Generation | Sherco Unit 3  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service 636
Accumulated Depreciation $ 499
Percent Owned 59.00%
Electric Generation | Sherco Common Facilities Units 1, 2 and 3  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 189
Accumulated Depreciation $ 128
Percent Owned 80.00%
Electric Generation | Sherco Substation  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 5
Accumulated Depreciation $ 4
Percent Owned 59.00%
Electric Transmission | Grand Meadow  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 11
Accumulated Depreciation $ 4
Percent Owned 50.00%
Electric Transmission | Huntley Wilmarth  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 49
Accumulated Depreciation $ 3
Percent Owned 50.00%
Electric Transmission | CapX2020 Transmission  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 855
Accumulated Depreciation $ 160
Percent Owned 51.00%
[1] Projects additionally include $10 million in CWIP.
v3.25.0.1
Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 364 $ 250
Regulatory assets $ 813 837
Regulatory Asset, Amortization Period 4 years  
Regulatory assets not currently earning a return $ 562 479
Minimum [Member]    
Regulatory Assets [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Minimum [Member] | Conservation Programs    
Regulatory Assets [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Maximum [Member]    
Regulatory Assets [Line Items]    
Regulatory Liability, Amortization Period 2 years  
Pension and Retiree Medical Obligations    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 21 18
Regulatory assets 339 340
Recoverable Deferred Taxes on AFUDC Recorded in Plant    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 0 0
Regulatory assets 137 127
Excess deferred taxes - TCJA    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 8 8
Regulatory assets 87 96
Deferred Purchased Natural Gas and Electric Energy Costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 51 16
Regulatory assets $ 25 58
Deferred Purchased Natural Gas and Electric Energy Costs | Minimum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 1 year  
Deferred Purchased Natural Gas and Electric Energy Costs | Maximum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 2 years  
PI extended power update    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 4 4
Regulatory assets $ 34 38
Regulatory Asset, Amortization Period 10 years  
Benson purchase power agreement termination and asset purchase    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 10 10
Regulatory assets 26 36
MISO capacity revenue tracker    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 63 36
Regulatory assets $ 45 26
MISO capacity revenue tracker | Minimum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 1 year  
MISO capacity revenue tracker | Maximum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 2 years  
Contract Valuation Adjustments    
Regulatory Assets [Line Items]    
Regulatory Asset, Current [1] $ 7 9
Regulatory assets [1] 16 22
Purchased Power Agreements    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 1 1
Regulatory assets 16 20
Conservation Programs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current [2] 8 6
Regulatory assets [2] $ 15 19
Conservation Programs | Minimum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 1 year  
Conservation Programs | Maximum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 2 years  
Nuclear Refueling Outage Costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 51 43
Regulatory assets $ 20 19
Nuclear Refueling Outage Costs | Minimum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 2 years  
Nuclear Refueling Outage Costs | Maximum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 1 year  
Sales True-Up and Revenue Decoupling    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 60 7
Regulatory assets $ 23 2
Sales True-Up and Revenue Decoupling | Minimum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 1 year  
Sales True-Up and Revenue Decoupling | Maximum [Member]    
Regulatory Assets [Line Items]    
Regulatory Asset, Amortization Period 2 years  
Renewable Resources and Environmental Initiatives    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 34 38
Regulatory assets $ 0 0
Regulatory Asset, Amortization Period 1 year  
Gas Pipeline Inspection and Remediation Costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 30 37
Regulatory assets $ 0 0
Regulatory Asset, Amortization Period 1 year  
Other    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 16 17
Regulatory assets $ 30 $ 34
[1] Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[2] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions
v3.25.0.1
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [1] $ 543 $ 300
Regulatory Liability, Noncurrent [1] $ 2,155 2,097
Minimum [Member]    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Maximum [Member]    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 2 years  
Deferred income tax adjustments and TCJA refunds    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [2] $ 5 5
Regulatory Liability, Noncurrent [2] 1,105 1,157
Plant Removal Costs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 0 0
Regulatory Liability, Noncurrent 815 741
Asset Retirement Obligation Costs [Member]    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [3] 0 0
Regulatory Liability, Noncurrent [3] 161 90
Renewable Resources and Environmental Initiatives    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 16 9
Regulatory Liability, Noncurrent 38 27
Contract Valuation Adjustments    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [4] 21 16
Regulatory Liability, Noncurrent [4] $ 0 0
Contract Valuation Adjustments | Minimum [Member]    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Conservation Programs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current $ 41 27
Regulatory Liability, Noncurrent $ 0 0
Conservation Programs | Minimum [Member]    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Deferred Electric Energy Costs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [5] $ 348 143
Regulatory Liability, Noncurrent [5] 12 0
Other Regulatory Liabilities    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 112 100
Regulatory Liability, Noncurrent 24 82
Other Current Liabilities    
Regulatory Liabilities [Line Items]    
Entity's Recorded Provision for Revenue Subject To Refund $ 3 $ 187
[1] Revenue subject to refund of $3 million and $187 million for 2024 and 2023, respectively, is included in other current liabilities.
[2] Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.
[3] Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
[4] Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion
[5] Includes Nuclear PTCs.
v3.25.0.1
Short-Term Debt (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2024
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Short-term Debt [Line Items]        
Short-term Debt $ 195 $ 195 $ 165  
Money Pool [Member]        
Short-term Debt [Line Items]        
Line of Credit Facility, Maximum Borrowing Capacity 250 250 250 $ 250
Short-term Debt 0 0 0 0
Short-term Debt, Average Outstanding Amount 31 10 17 0
Short-term Debt, Maximum Amount Outstanding During Period $ 139 $ 139 $ 135 $ 4
Line of Credit Facility, Interest Rate During Period 4.62% 4.82% 4.97% 3.87%
Commercial Paper [Member]        
Short-term Debt [Line Items]        
Line of Credit Facility, Maximum Borrowing Capacity $ 700 $ 700 $ 700 $ 700
Short-term Debt 195 195 165 207
Short-term Debt, Average Outstanding Amount 24 54 92 21
Short-term Debt, Maximum Amount Outstanding During Period $ 215 $ 400 $ 441 $ 290
Short-term Debt, Weighted Average Interest Rate, at Point in Time 4.63% 4.63% 5.47% 4.64%
Line of Credit Facility, Interest Rate During Period 4.62% 5.39% 4.99% 4.14%
v3.25.0.1
Letters of Credit (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Line of Credit Facility [Line Items]    
Short-term Debt $ 195 $ 165
Letter of Credit [Member]    
Line of Credit Facility [Line Items]    
Short-term Debt $ 12  
Letter of Credit [Member]    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Expiration Period 1 year  
Bilateral Credit Agreement [Member] | Letter of Credit [Member]    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity $ 75  
Short-term Debt $ 74 $ 65
v3.25.0.1
Credit Facilities (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Line of Credit Facility [Line Items]    
Short-term Debt $ 195 $ 165
Letter of Credit [Member]    
Line of Credit Facility [Line Items]    
Short-term Debt 12  
Bilateral Credit Agreement [Member] | Letter of Credit [Member]    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity 75  
Short-term Debt $ 74 $ 65
Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent) [1] 47.00% 47.70%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased $ 150  
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval [2] 2  
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed 65.00%  
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions 15.00%  
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions $ 75  
Line of Credit Facility, Maximum Borrowing Capacity [3] 700  
Drawn [4] 207  
Line of Credit Facility, Remaining Borrowing Capacity 493  
Direct advances on the credit facility outstanding $ 0 $ 0
[1] The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
[2] All extension requests are subject to majority bank group approval.
[3] This credit facility matures in September 2027.
[4] Includes outstanding commercial paper and letters of credit.
v3.25.0.1
Long-Term Debt (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Long-Term Borrowings and Other Financing Instruments    
Unamortized discount $ (49) $ (49)
Unamortized debt expense (80) (73)
Long-term Debt, Current Maturities 250 0
Long-term Debt 7,607 7,330
2025 250  
2026 0  
2027 0  
2028 150  
2029 0  
First Mortgage Bonds | Series Due July 1, 2025 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (250) (250)
Debt Instrument, Interest Rate, Stated Percentage 7.125%  
First Mortgage Bonds | Series Due March 1, 2028 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (150) (150)
Debt Instrument, Interest Rate, Stated Percentage 6.50%  
First Mortgage Bonds | Series Due April 1, 2031    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (425) (425)
Debt Instrument, Interest Rate, Stated Percentage 2.25%  
First Mortgage Bonds | Series Due July 1, 2037 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (350) (350)
Debt Instrument, Interest Rate, Stated Percentage 6.20%  
First Mortgage Bonds | Series Due Nov. 1, 2039 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (300) (300)
Debt Instrument, Interest Rate, Stated Percentage 5.35%  
First Mortgage Bonds | Series Due Aug. 15, 2040 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (250) (250)
Debt Instrument, Interest Rate, Stated Percentage 4.85%  
First Mortgage Bonds | Series Due Aug. 15, 2042 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (500) (500)
Debt Instrument, Interest Rate, Stated Percentage 3.40%  
First Mortgage Bonds | Series Due May 15, 2044 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (300) (300)
Debt Instrument, Interest Rate, Stated Percentage 4.125%  
First Mortgage Bonds | Series Due Aug. 15, 2045 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (300) (300)
Debt Instrument, Interest Rate, Stated Percentage 4.00%  
First Mortgage Bonds | Series Due May 15, 2046 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (350) (350)
Debt Instrument, Interest Rate, Stated Percentage 3.60%  
First Mortgage Bonds | Series Due Sept. 15, 2047 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (600) (600)
Debt Instrument, Interest Rate, Stated Percentage 3.60%  
First Mortgage Bonds | Series Due June 1, 2051 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [1] $ (700) (700)
Debt Instrument, Interest Rate, Stated Percentage [1] 2.60%  
First Mortgage Bonds | Series Due June 1, 2051 [Member] | Xcel Energy [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [1] $ (166) 0
Debt Instrument, Interest Rate, Stated Percentage [1] 2.60%  
First Mortgage Bonds | Series Due April 1, 2052    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (425) (425)
Debt Instrument, Interest Rate, Stated Percentage 3.20%  
First Mortgage Bonds | Series Due June 1, 2052    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (500) (500)
Debt Instrument, Interest Rate, Stated Percentage 4.50%  
First Mortgage Bonds | Series Due July 15, 2035    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (250) (250)
Debt Instrument, Interest Rate, Stated Percentage 5.25%  
First Mortgage Bonds | Series Due June 1, 2036    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (400) (400)
Debt Instrument, Interest Rate, Stated Percentage 6.25%  
First Mortgage Bonds | Series Due March 1, 2050    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (600) (600)
Debt Instrument, Interest Rate, Stated Percentage 2.90%  
First Mortgage Bonds | Series Due May 15, 2053    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [2] $ (800) (800)
Debt Instrument, Interest Rate, Stated Percentage [2] 5.10%  
First Mortgage Bonds | Series Due March 15, 2054    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [3] $ (700) 0
Debt Instrument, Interest Rate, Stated Percentage [3] 5.40%  
Long-term Debt    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (2) $ (2)
Letter of Credit [Member]    
Long-Term Borrowings and Other Financing Instruments    
Line of Credit Facility, Expiration Period 1 year  
[1] During 2024, Xcel Energy Inc. purchased a portion of these NSP-Minnesota first mortgage bonds for $105 million. Interest expense related to these repurchased bonds was immaterial for the year ended Dec. 31, 2024.
[2] 2023 financing.
[3] 2024 financing.
v3.25.0.1
Dividend and Other Capital-Related Restrictions (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Dividend and Other Capital-Related Restrictions [Abstract]  
Equity to total capitalization ratio, low end of range (in hundredths) 47.60%
Equity to total capitalization ratio, high end of range (in hundredths) 58.20%
Equity to total capitalization ratio 53.00%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions $ 1,809
Capitalization, Short term debt, long term debt and equity 17,490
Maximum total capitalization $ 17,800
v3.25.0.1
Revenues Revenues (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Total revenue from contracts with customers      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers $ 5,345 $ 5,709 $ 6,368
Retail      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 4,287 4,581 4,865
Retail | Residential      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 1,831 1,933 2,011
Retail | C&I      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 2,412 2,607 2,809
Retail | Other      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 44 41 45
Wholesale      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 319 354 668
Transmission      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 262 263 287
Interchange      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 477 511 548
Alternative and Other [Member]      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 422 334 316
Regulated Electric | Total revenue from contracts with customers      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 4,750 4,966 5,361
Regulated Electric | Retail      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 3,723 3,856 3,877
Regulated Electric | Retail | Residential      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 1,496 1,524 1,463
Regulated Electric | Retail | C&I      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 2,191 2,298 2,376
Regulated Electric | Retail | Other      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 36 34 38
Regulated Electric | Wholesale      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 319 354 668
Regulated Electric | Transmission      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 262 263 287
Regulated Electric | Interchange      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 446 493 529
Regulated Electric | Alternative and Other [Member]      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 349 275 256
Regulated Natural Gas | Total revenue from contracts with customers      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 580 695 962
Regulated Natural Gas | Retail      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 549 677 943
Regulated Natural Gas | Retail | Residential      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 328 368 510
Regulated Natural Gas | Retail | C&I      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 221 309 433
Regulated Natural Gas | Retail | Other      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
Regulated Natural Gas | Wholesale      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
Regulated Natural Gas | Transmission      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
Regulated Natural Gas | Interchange      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 31 18 19
Regulated Natural Gas | Alternative and Other [Member]      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 73 59 60
All Other | Total revenue from contracts with customers      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 15 48 45
All Other | Retail      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 15 48 45
All Other | Retail | Residential      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 7 41 38
All Other | Retail | C&I      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
All Other | Retail | Other      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 8 7 7
All Other | Wholesale      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
All Other | Transmission      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
All Other | Interchange      
Disaggregation of Revenue [Line Items]      
Total revenue from contracts with customers 0 0 0
All Other | Alternative and Other [Member]      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 0 0 0
Total revenues      
Disaggregation of Revenue [Line Items]      
Total revenues 5,767 6,043 6,684
Total revenues | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Total revenues 5,099 5,241 5,617
Total revenues | Regulated Natural Gas      
Disaggregation of Revenue [Line Items]      
Total revenues 653 754 1,022
Total revenues | All Other      
Disaggregation of Revenue [Line Items]      
Total revenues $ 15 $ 48 $ 45
v3.25.0.1
Unrecognized Tax Benefits (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Income Tax Disclosure [Abstract]        
Unrecognized tax benefit — Permanent tax positions $ 20 $ 18    
Unrecognized tax benefit — Temporary tax positions 0 0    
Total unrecognized tax benefit 20 18 $ 34 $ 26
Additions based on tax positions related to the current year 3 2 2  
Additions for tax positions of prior years 0 1 6  
Reductions for tax positions of prior years (1) (18) 0  
NOL and tax credit carryforwards (17) (18)    
Unrecognized Tax Benefits, Income Tax Penalties Expense 0 0 0  
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1 0 1 (3) $ (2)
Interest (expense) benefit related to unrecognized tax benefits (1) $ (4) $ (1)  
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit $ 20      
v3.25.0.1
Other Income Tax Matters (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Tax [Line Items]      
Federal detriment $ 16 $ 15  
Federal Benefit 15 14  
Tax Credit Carryforward, Amount 815 777  
State NOL carryforwards 0 1  
state tax credit carryforward, net of federal detirment [1] 60 55  
valuation allowances for state credit carryforwards, net of federal benefit [2] $ (57) $ (52)  
Federal statutory rate 21.00% 21.00% 21.00%
State income tax on pretax income, net of federal tax effect 7.10% 7.00% 7.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent [3] (99.40%) (39.50%) (39.60%)
Plant regulatory differences (b) [4] (9.20%) (5.70%) (6.70%)
Other tax credits, net NOL & tax credit allowances (1.90%) (1.30%) (1.30%)
Other, net 0.90% 0.30% (0.30%)
Effective income tax rate (81.50%) (18.20%) (19.90%)
Income tax benefit $ (356) $ (109) $ (112)
Deferred tax expense (benefit) excluding items below 246 326 (283)
Adjustments to deferred income taxes for wind production tax credit cash transfers [5] (325) (150) 0
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (99) (114) 70
Tax (expense) benefit allocated to other comprehensive income and other (6) 2 (1)
Deferred tax (benefit) expense 184 64 214
Operating Lease, Liability 414    
Tax Credit Carryforward, Valuation Allowance (11) (5)  
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities $ 0 (1) 0
Effective Income Tax Rate Reconciliation, Tax Credit, Wind, Solar and Nuclear PTCs, Percent 39.50%    
income tax expense [Member]      
Income Tax [Line Items]      
Current federal tax (benefit) expense $ (149) (154) 70
Current state tax (benefit) expense (25) 3 26
Current change in unrecognized tax expense (benefit) 3 (21) 8
Deferred federal tax (benefit) expense (244) 5 (237)
Deferred state tax expense 61 51 23
Deferred change in unrecognized tax (benefit) expense (1) 8 0
Deferred ITCs (1) (1) (2)
Income tax benefit (356) (109) $ (112)
Net Deferred Tax Liablility [Member]      
Income Tax [Line Items]      
Tax Credit Carryforward, Amount 875 832 [6]  
Deferred ITCs 4 4 [6]  
Deferred tax (benefit) expense 1,370 1,341 [6]  
Differences between book and tax bases of property 3,150 2,938 [6]  
Regulatory assets 234 173 [6]  
Operating lease assets 115 129 [6]  
Deferred fuel costs 21 20 [6]  
Deferred tax liability - Pension expense 67 64 [6]  
Other 21 9 [6]  
Total deferred tax liabilities 3,608 3,333 [6]  
Regulatory liabilities 358 306 [6]  
Operating Lease, Liability 115 129 [6]  
Tax Credit Carryforward, Valuation Allowance (68) (57) [6]  
other employee benefits 28 31 [6]  
Other 48 37 [6]  
Net deferred tax liability 2,238 1,992 [6]  
Deferred Tax Assets Rate Refund $ 10 $ 59 [6]  
[1] State tax credit carryforwards are net of federal detriment of $16 million and $15 million as of Dec. 31, 2024 and 2023, respectively.
[2] Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $14 million as of Dec. 31, 2024 and 2023, respectively.
[3] Wind, Solar, and Nuclear PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings. Nuclear PTCs, newly available in 2024, resulted in benefits of 39.5% to the ETR for the year ended Dec. 31, 2024.
[4] Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
[5] Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.
[6] Prior periods have been reclassified to conform to current year presentation
v3.25.0.1
Nuclear Decommissioning Fund (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Investments [Abstract]    
Miscellaneous investments $ 54 $ 51
Final Contractual Maturity [Abstract]    
Due in 1 Year or Less 7  
Due in 1 to 5 Years 308  
Due in 5 to 10 Years 269  
Due after 10 Years 262  
Total 846  
Debt Securities, Available-for-Sale, Unrealized Gain 1,400 1,200
Debt Securities, Available-for-Sale, Unrealized Loss 49 29
Fair Value Measured on a Recurring Basis | Cost    
Investments [Abstract]    
Decommissioning Fund Investments 2,130 [1] 2,054 [2]
Fair Value Measured on a Recurring Basis | Cost | Cash equivalents    
Investments [Abstract]    
Cash equivalents 39 [1] 41 [2]
Fair Value Measured on a Recurring Basis | Cost | Commingled Funds    
Investments [Abstract]    
Investments, Fair Value Disclosure 703 [1] 721 [2]
Fair Value Measured on a Recurring Basis | Cost | Debt Securities [Member]    
Investments [Abstract]    
Debt Securities, Available-for-Sale, Excluding Accrued Interest 866 [1] 784 [2]
Fair Value Measured on a Recurring Basis | Cost | Equity Securities    
Investments [Abstract]    
Equity Securities, FV-NI, Current 522 [1] 508 [2]
Fair Value Measured on a Recurring Basis | Fair Value    
Investments [Abstract]    
Alternative Investment 1,025 [1] 1,049 [2]
Decommissioning Fund Investments 3,494 [1] 3,211 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents    
Investments [Abstract]    
Cash equivalents 39 [1] 41 [2]
Alternative Investment 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds    
Investments [Abstract]    
Alternative Investment 1,025 [1] 1,049 [2]
Investments, Fair Value Disclosure 1,025 [1] 1,049 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Debt Securities [Member]    
Investments [Abstract]    
Alternative Investment 0 [1] 0 [2]
Debt Securities, Available-for-Sale, Excluding Accrued Interest 846 [1] 780 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Equity Securities    
Investments [Abstract]    
Alternative Investment 0 [1] 0 [2]
Equity Securities, FV-NI, Current 1,584 [1] 1,341 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1    
Investments [Abstract]    
Decommissioning Fund Investments 1,622 [1] 1,380 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash equivalents    
Investments [Abstract]    
Cash equivalents 39 [1] 41 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled Funds    
Investments [Abstract]    
Investments, Fair Value Disclosure 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Debt Securities [Member]    
Investments [Abstract]    
Debt Securities, Available-for-Sale, Excluding Accrued Interest 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Equity Securities    
Investments [Abstract]    
Equity Securities, FV-NI, Current 1,583 [1] 1,339 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2    
Investments [Abstract]    
Decommissioning Fund Investments 833 [1] 773 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Cash equivalents    
Investments [Abstract]    
Cash equivalents 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled Funds    
Investments [Abstract]    
Investments, Fair Value Disclosure 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Debt Securities [Member]    
Investments [Abstract]    
Debt Securities, Available-for-Sale, Excluding Accrued Interest 832 [1] 771 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Equity Securities    
Investments [Abstract]    
Equity Securities, FV-NI, Current 1 [1] 2 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3    
Investments [Abstract]    
Decommissioning Fund Investments 14 [1] 9 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Cash equivalents    
Investments [Abstract]    
Cash equivalents 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled Funds    
Investments [Abstract]    
Investments, Fair Value Disclosure 0 [1] 0 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Debt Securities [Member]    
Investments [Abstract]    
Debt Securities, Available-for-Sale, Excluding Accrued Interest 14 [1] 9 [2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Equity Securities    
Investments [Abstract]    
Equity Securities, FV-NI, Current 0 [1] 0 [2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value    
Investments [Abstract]    
Decommissioning Fund Investments $ 3,500 $ 3,200
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.
[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.
v3.25.0.1
Interest Rate Derivatives (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Interest Rate Swap [Member]  
Interest Rate Derivatives [Abstract]  
Derivative Liability, Notional Amount $ 0
v3.25.0.1
Commodity Derivatives (Details)
MWh in Millions, MMBTU in Millions, $ in Millions
Dec. 31, 2024
USD ($)
MWh
MMBTU
Dec. 31, 2023
MWh
MMBTU
Electric Commodity    
Derivative [Line Items]    
Notional amount | MWh [1],[2] 31 38
Natural Gas Commodity    
Derivative [Line Items]    
Notional amount | MMBTU [1],[2] 57 64
Cash Flow Hedges    
Derivative [Line Items]    
Derivative Instruments in Hedges, at Fair Value, Net | $ $ 0  
[1] Not reflective of net positions in the underlying commodities.
[2] Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.
v3.25.0.1
Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk
$ in Millions
Dec. 31, 2024
USD ($)
Counterparty
Derivative [Line Items]  
Number of most significant counterparties 10
Municipal or Cooperative Entities or Other Utilities  
Derivative [Line Items]  
Number of most significant counterparties 3
External Credit Rating, Investment Grade  
Derivative [Line Items]  
Number of most significant counterparties 6
Credit exposure for the most significant counterparties | $ $ 20
Percentage of credit exposure for the most significant counterparties 22.00%
Internal Investment Grade [Member]  
Derivative [Line Items]  
Number of most significant counterparties 1
Credit exposure for the most significant counterparties | $ $ 27
Percentage of credit exposure for the most significant counterparties 29.00%
External Credit Rating, Noninvestment Grade  
Derivative [Line Items]  
Number of most significant counterparties 3
Credit exposure for the most significant counterparties | $ $ 43
Percentage of credit exposure for the most significant counterparties 47.00%
v3.25.0.1
Qualifying Cash Flow Hedges (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Fair Value Hedges, Net $ 0 $ 0 $ 0
Other Derivative Instruments      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss 0 0 0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities 16 49 7
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 21 (45) (3)
Derivative, Gain (Loss) on Derivative, Net (17) (10) 9
Electric Commodity Contract | Other Derivative Instruments      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss 0 0 0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities 18 48 7
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) [1] 21 (45) (1)
Derivative, Gain (Loss) on Derivative, Net 0 0 0
Natural Gas Commodity Contract | Other Derivative Instruments      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss 0 0  
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities (2) 1  
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 2 [2]
Derivative, Gain (Loss) on Derivative, Net [2],[3] (7) (8) (8)
Commodity Trading Contract | Other Derivative Instruments      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 0
Derivative, Gain (Loss) on Derivative, Net [4] (10) (2) 17
Cash Flow Hedges | Designated as Hedging Instrument      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss (16) 3  
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities 0 0  
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss 1 1 1
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 0
Derivative, Gain (Loss) on Derivative, Net 0 0 0
Cash Flow Hedges | Interest Rate Contract | Designated as Hedging Instrument      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss (16) 3  
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities 0 0  
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss [5] 1 1 1
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 0
Derivative, Gain (Loss) on Derivative, Net $ 0 $ 0 $ 0
[1] Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value.
[2] Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
[3] Relates primarily to option premium amortization.
[4] Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
[5] Recorded to interest charges.
v3.25.0.1
Credit Related Contingent Features (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Fair Value Disclosures [Abstract]    
Derivative instruments in a gross liability position $ 11 $ 12
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value 63 80
Collateral posted related to adequate assurance clauses in derivative contracts $ 0 $ 0
v3.25.0.1
Recurring Fair Value Measurements (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Derivatives, Fair Value [Line Items]      
Derivative instruments $ 36 $ 50  
Derivative Liability, Current 31 44  
Return Cash Collateral 0 0  
Reclaim Cash Collateral 1 3  
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]      
Derivative instruments 77 86  
Derivative instruments 67 61  
Commodity Contract [Member]      
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]      
Balance at beginning of period 51 107 $ 56
Purchases [1] 72 98 157
Settlements [1] (61) (65) (195)
Gains (losses) recognized in earnings [2] (9) 15 91
Net gains (losses) recognized as regulatory assets and liabilities [1] (21) (104) (2)
Balance at end of period 32 51 $ 107
Fair Value Measured on a Recurring Basis      
Derivatives, Fair Value [Line Items]      
Derivative instruments 36 50  
Derivative Liability, Current 25 38  
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]      
Derivative instruments 61 64  
Derivative instruments 67 61  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Commodity Contract [Member]      
Derivatives, Fair Value [Line Items]      
Derivative instruments 11 29  
Derivative Liability, Current 24 28  
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]      
Derivative instruments 61 64  
Derivative instruments 67 61  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 23 23  
Netting [3] (2) (7)  
Derivative instruments 21 16  
Derivative Liability, Current 0 0  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 0 0  
Derivative Liability, Gross 0    
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 23 23  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 4 5  
Netting [3] 0 0  
Derivative instruments 4 5  
Derivative Liability, Current 1 3  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 4 5  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 0 0  
Fair Value Measured on a Recurring Basis | Designated as Hedging Instrument | Interest Rate Swap [Member] | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Current 0 7  
Fair Value Measured on a Recurring Basis | Other Current Assets      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 60 99  
Netting [3] (24) (49)  
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 5 7  
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 24 37  
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 31 55  
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member]      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 33 71  
Netting [3] (22) (42)  
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 5 7  
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 20 32  
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 8 32  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 83 95  
Netting [3] (16) (34)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 3 7  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 33 43  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 47 45  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member]      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 83 95  
Netting [3] (16) (34)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 3 7  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 33 43  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 47 45  
Fair Value Measured on a Recurring Basis | Other Current Liabilities      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 48 88  
Netting [3] (23) (50)  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 6 6  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 36 70  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 6 12  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member]      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 46 71  
Netting [3] (22) (43)  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 6 6  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 35 60  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 5 5  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 1 7  
Netting [3] (1) (7)  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross   0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 1 7  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 1 3  
Netting [3] 0 0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 1 3  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap [Member]      
Derivatives, Fair Value [Line Items]      
Netting 0 0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap [Member] | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 7  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap [Member] | Level 1 | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap [Member] | Level 2 | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 7  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap [Member] | Level 3 | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 79 100  
Netting [3] (18) (36)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 9 14  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 30 49  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 40 37  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member]      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 79 100  
Netting [3] (18) (36)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 9 14  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 30 49  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member] | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 40 37  
Fair Value, Measurements, Nonrecurring | Purchased Power Agreements      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Current [4] 6 6  
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]      
Derivative instruments [4] $ 16 $ 22  
[1] Relates primarily to FTR instruments administered by MISO.
[2] Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the consolidated income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
[3] NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2024 and 2023, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2024 and 2023, derivative assets and liabilities include rights to reclaim cash collateral of $1 million and $3 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[4] NSP-Minnesota currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
v3.25.0.1
Fair Value of Long-Term Debt (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Financial Liabilities, Balance Sheet Groupings [Abstract]    
Long-term Debt, Gross $ 7,857 $ 7,330
Long-term debt, Fair Value 6,755 6,561
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term Debt, Gross 7,857 7,330
Long-term debt, Fair Value 6,755 6,561
Xcel Energy [Member]    
Financial Liabilities, Balance Sheet Groupings [Abstract]    
Long-term Debt, Gross 166 0
Long-term debt, Fair Value 99 0
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term Debt, Gross 166 0
Long-term debt, Fair Value $ 99 $ 0
v3.25.0.1
Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details) - USD ($)
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]      
annual interest crediting rates $ 4.89 $ 4.67 $ 4.86
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Pension Plan        
Pension Benefits [Abstract]        
Fair value of plan assets   $ 528 [1] $ 562 [1] $ 570
Total benefit obligation   612 660 657
Net benefit cost recognized for financial reporting   $ 30 $ 38 $ 34
Expected average long-term rate of return on assets (as a percent)   7.25% 7.25% 6.60%
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   100.00% 100.00%  
Pension Plan | Long-duration fixed income and interest rate swap securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   38.00% 38.00%  
Pension Plan | Domestic and international equity securities        
Pension Benefits [Abstract]        
Fair value of plan assets [1]   $ 6 $ 8  
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   31.00% 31.00%  
Pension Plan | Short-to-intermediate fixed income securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   9.00% 9.00%  
Pension Plan | Alternative investments        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   20.00% 20.00%  
Pension Plan | Cash        
Pension Benefits [Abstract]        
Fair value of plan assets [1]   $ 24 $ 46  
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   2.00% 2.00%  
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan        
Pension Benefits [Abstract]        
Total benefit obligation   $ 13 $ 12  
Forecast [Member] | Pension Plan        
Pension Benefits [Abstract]        
Expected average long-term rate of return on assets for next fiscal year (as a percent) 7.25%      
[1] See Note 8 for further information regarding fair value measurement inputs and methods.
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]      
assets transferred $ 0 $ 0  
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 528 [1] 562 [1] $ 570
Pension Plan | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 30 164  
Pension Plan | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 124 132  
Pension Plan | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 1 1  
Pension Plan | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [1] 373 265  
Pension Plan | Cash      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 24 46  
Pension Plan | Cash | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 24 46  
Pension Plan | Cash | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Cash | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Cash | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [1] 0 0  
Pension Plan | Commingled Funds      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 373 375  
Pension Plan | Commingled Funds | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 110  
Pension Plan | Commingled Funds | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Commingled Funds | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Commingled Funds | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [1] 373 265  
Pension Plan | Debt Securities [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 124 128  
Pension Plan | Debt Securities [Member] | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Debt Securities [Member] | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 123 127  
Pension Plan | Debt Securities [Member] | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 1 1  
Pension Plan | Debt Securities [Member] | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [1] 0 0  
Pension Plan | Domestic and international equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 6 8  
Pension Plan | Domestic and international equity securities | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 6 8  
Pension Plan | Domestic and international equity securities | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Domestic and international equity securities | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Domestic and international equity securities | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [1] 0 0  
Pension Plan | Other      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 1 5  
Pension Plan | Other | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Other | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 1 5  
Pension Plan | Other | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [1] 0 0  
Pension Plan | Other | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [1] 0 0  
Postretirement Benefits Plan      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount 2 [2] 3 $ 5
Postretirement Benefits Plan | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 1 2  
Postretirement Benefits Plan | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [2] 1 1  
Postretirement Benefits Plan | Commingled Funds      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 1 1  
Postretirement Benefits Plan | Commingled Funds | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Commingled Funds | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Commingled Funds | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Commingled Funds | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [2] 1 1  
Postretirement Benefits Plan | Debt Securities [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 1 2  
Postretirement Benefits Plan | Debt Securities [Member] | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Debt Securities [Member] | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 1 2  
Postretirement Benefits Plan | Debt Securities [Member] | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Defined Benefit Plan, Plan Assets, Amount [2] 0 0  
Postretirement Benefits Plan | Debt Securities [Member] | Fair Value Measured at Net Asset Value Per Share      
Defined Benefit Plan Disclosure [Line Items]      
Plan assets at net asset value [2] $ 0 $ 0  
[1] See Note 8 for further information regarding fair value measurement inputs and methods.
[2] See Note 8 for further information on fair value measurement inputs and methods.
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details)
 1 Months Ended 12 Months Ended
Jan. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
plan
Dec. 31, 2023
USD ($)
Dec. 31, 2022
USD ($)
Cash Flows [Abstract]        
Number of pension plans to which contributions were made | plan   4    
Components of Net Periodic Benefit Cost (Credit) [Abstract]        
Liability, Defined Benefit Plan, Noncurrent   $ (151,000,000) $ (168,000,000)  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65   0.0700 0.0700  
Pension Plan        
Change in Projected Benefit Obligation [Roll Forward]        
Obligation at Jan. 1 $ 612,000,000 $ 660,000,000 $ 657,000,000  
Service cost   22,000,000 21,000,000 $ 27,000,000
Interest cost   34,000,000 36,000,000 25,000,000
Plan amendments   0 (1,000,000)  
Actuarial (gain) loss   (22,000,000) 30,000,000  
Benefit payments   (82,000,000) (83,000,000)  
Obligation at Dec. 31   612,000,000 660,000,000 657,000,000
Change in Fair Value of Plan Assets [Roll Forward]        
Fair value of plan assets at Jan. 1 528,000,000 [1] 562,000,000 [1] 570,000,000  
Actual return (loss) on plan assets   7,000,000 52,000,000  
Employer contributions   41,000,000 23,000,000  
Benefit payments   (82,000,000) (83,000,000)  
Fair value of plan assets at Dec. 31   528,000,000 [1] 562,000,000 [1] 570,000,000
Funded Status of Plans at Dec. 31 [Abstract]        
Funded status   (84,000,000) (98,000,000)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]        
Net loss   289,000,000 321,000,000  
Total   289,000,000 321,000,000  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]        
Current regulatory assets   14,000,000 11,000,000  
Noncurrent regulatory assets   275,000,000 310,000,000  
Total   $ 289,000,000 $ 321,000,000  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]        
Discount rate for year-end valuation (as a percent)   5.88% 5.49%  
Expected average long-term increase in compensation level (as a percent)   4.25% 4.25%  
Components of Net Periodic Benefit Cost (Credit) [Abstract]        
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement [2]   $ (37,000,000) $ 0 $ (38,000,000)
Defined Benefit Plan, Accumulated Benefit Obligation   557,000,000 599,000,000  
Liability, Defined Benefit Plan, Current   0 0  
Liability, Defined Benefit Plan, Noncurrent   (84,000,000) (98,000,000)  
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position   $ (84,000,000) $ (98,000,000)  
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase   4.25% 4.25% 3.75%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income   $ 0 $ 0  
Defined Benefit Plan, Accumulated Benefit Obligation   $ (557,000,000) $ (599,000,000)  
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets   7.25% 7.25% 6.60%
Service cost   $ 22,000,000 $ 21,000,000 $ 27,000,000
Interest cost   34,000,000 36,000,000 25,000,000
Expected return on plan assets   (46,000,000) (46,000,000) (48,000,000)
Amortization of prior service cost (credit)   0 0 0
Amortization of net loss   13,000,000 11,000,000 24,000,000
Net periodic pension cost   60,000,000 22,000,000 66,000,000
Effects of regulation   (30,000,000) 16,000,000 (32,000,000)
Net benefit cost recognized for financial reporting   30,000,000 38,000,000 34,000,000
Pension Plan | NSP Minnesota [Member]        
Change in Fair Value of Plan Assets [Roll Forward]        
Fair value of plan assets at Jan. 1 [3]   3,000,000    
Fair value of plan assets at Dec. 31 [3]     3,000,000  
Cash Flows [Abstract]        
Total contributions to Xcel Energy's pension plans during the period   41,000,000 23,000,000 5,000,000
Postretirement Benefits Plan        
Change in Projected Benefit Obligation [Roll Forward]        
Obligation at Jan. 1 41,000,000 42,000,000 48,000,000  
Service cost   1,000,000 0 0
Interest cost   2,000,000 3,000,000 2,000,000
Plan amendments   0 0  
Actuarial (gain) loss   1,000,000 (2,000,000)  
Benefit payments   (5,000,000) (7,000,000)  
Obligation at Dec. 31   41,000,000 42,000,000 48,000,000
Change in Fair Value of Plan Assets [Roll Forward]        
Fair value of plan assets at Jan. 1 2,000,000 [3] 3,000,000 5,000,000  
Actual return (loss) on plan assets   0 0  
Employer contributions   4,000,000 5,000,000  
Benefit payments   (5,000,000) (7,000,000)  
Fair value of plan assets at Dec. 31   2,000,000 [3] 3,000,000 5,000,000
Funded Status of Plans at Dec. 31 [Abstract]        
Funded status   (39,000,000) (39,000,000)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]        
Net loss   14,000,000 15,000,000  
Total   14,000,000 15,000,000  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]        
Current regulatory assets   0 0  
Noncurrent regulatory assets   13,000,000 14,000,000  
Total   $ 14,000,000 $ 15,000,000  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]        
Discount rate for year-end valuation (as a percent)   5.88% 5.54%  
Components of Net Periodic Benefit Cost (Credit) [Abstract]        
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement [2]   $ 0 $ 0 $ 0
Liability, Defined Benefit Plan, Current   (3,000,000) (2,000,000)  
Liability, Defined Benefit Plan, Noncurrent   (36,000,000) (37,000,000)  
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position   $ (39,000,000) $ (39,000,000)  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65   7.50% 5.50%  
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate   4.50% 4.50%  
Period until ultimate trend rate is reached (in years)   $ 9 $ 6  
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase   0.00% 0.00% 0.00%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income   $ 1,000,000 $ 1,000,000  
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets   5.00% 5.00% 4.10%
Service cost   $ 1,000,000 $ 0 $ 0
Interest cost   2,000,000 3,000,000 2,000,000
Expected return on plan assets   0 0 0
Amortization of prior service cost (credit)   0 (1,000,000) (3,000,000)
Amortization of net loss   0 0 1,000,000
Net periodic pension cost   3,000,000 2,000,000 0
Effects of regulation   0 0 0
Net benefit cost recognized for financial reporting   $ 3,000,000 $ 2,000,000 $ 0
Subsequent Event | Pension Plan | NSP Minnesota [Member]        
Cash Flows [Abstract]        
Total contributions to Xcel Energy's pension plans during the period $ 54,000,000      
[1] See Note 8 for further information regarding fair value measurement inputs and methods.
[2] A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024 and 2022, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $37 million and $38 million, respectively, which was not recognized in earnings due to the effects of regulation. There were no settlement charges recorded for the qualified pension plans in 2023.
[3] See Note 8 for further information on fair value measurement inputs and methods.
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Dec. 31, 2022
USD ($)
Postretirement Health Care Benefits [Abstract]      
Estimated costs of health plan subsidies - VRP $ 7 $ 8  
Estimated cost of other medical benefits - VRP $ 1 $ 1  
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate, VRP 0.0500 0.0550  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 0.0700 0.0700  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed and Ultimate Trend Assumption, Ultimate Trend Assumption 0.0450    
Years until ultimate trend is reached 9 years    
Postretirement Benefits Plan      
Postretirement Health Care Benefits [Abstract]      
Total benefit obligation $ 41 $ 42 $ 48
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) $ 3 $ 2 0
Target pension asset allocations (as a percent) 100.00% 100.00%  
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | Parent Company [Member]      
Postretirement Health Care Benefits [Abstract]      
Total benefit obligation $ 13 $ 12  
Pension Plan      
Postretirement Health Care Benefits [Abstract]      
Total benefit obligation 612 660 657
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) $ 30 $ 38 $ 34
Target pension asset allocations (as a percent) 100.00% 100.00%  
Domestic and international equity securities | Postretirement Benefits Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 25.00% 9.00%  
Domestic and international equity securities | Pension Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 31.00% 31.00%  
Long-duration fixed income and interest rate swap securities | Postretirement Benefits Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 0.00% 0.00%  
Long-duration fixed income and interest rate swap securities | Pension Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 38.00% 38.00%  
Short-to-intermediate fixed income securities | Postretirement Benefits Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 61.00% 77.00%  
Short-to-intermediate fixed income securities | Pension Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 9.00% 9.00%  
Alternative investments | Postretirement Benefits Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 11.00% 13.00%  
Alternative investments | Pension Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 20.00% 20.00%  
Cash | Postretirement Benefits Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 3.00% 1.00%  
Cash | Pension Plan      
Postretirement Health Care Benefits [Abstract]      
Target pension asset allocations (as a percent) 2.00% 2.00%  
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefits Plan - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets $ 2 [1] $ 3 $ 5
Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 0 0  
Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 1 2  
Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 0 0  
Debt Securities [Member]      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 1 2  
Debt Securities [Member] | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 0 0  
Debt Securities [Member] | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 1 2  
Debt Securities [Member] | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 0 0  
Commingled Funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 1 1  
Commingled Funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 0 0  
Commingled Funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] 0 0  
Commingled Funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets [1] $ 0 $ 0  
[1] See Note 8 for further information on fair value measurement inputs and methods.
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Funded Status of Plans at Dec. 31 [Abstract]      
Noncurrent liabilities $ (151,000,000) $ (168,000,000)  
Significant Assumptions Used to Measure Costs [Abstract]      
Estimated costs of health plan subsidies - VRP 7,000,000 8,000,000  
Estimated cost of other medical benefits - VRP $ 1,000,000 $ 1,000,000  
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate, VRP 0.0500 0.0550  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 0.0700 0.0700  
Pension Plan      
Change in Projected Benefit Obligation [Roll Forward]      
Obligation at Jan. 1 $ 660,000,000 $ 657,000,000  
Service cost 22,000,000 21,000,000 $ 27,000,000
Interest cost 34,000,000 36,000,000 25,000,000
Actuarial (gain) loss (22,000,000) 30,000,000  
Benefit payments (82,000,000) (83,000,000)  
Obligation at Dec. 31 612,000,000 660,000,000 657,000,000
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 562,000,000 [1] 570,000,000  
Actual return (loss) on plan assets 7,000,000 52,000,000  
Employer contributions 41,000,000 23,000,000  
Benefit payments (82,000,000) (83,000,000)  
Fair value of plan assets at Dec. 31 528,000,000 [1] 562,000,000 [1] 570,000,000
Funded Status of Plans at Dec. 31 [Abstract]      
Funded status (84,000,000) (98,000,000)  
Current liabilities 0 0  
Noncurrent liabilities (84,000,000) (98,000,000)  
Net postretirement amounts recognized on consolidated balance sheets (84,000,000) (98,000,000)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 289,000,000 321,000,000  
Total 289,000,000 321,000,000  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]      
Noncurrent regulatory assets 275,000,000 310,000,000  
Net-of-tax accumulated other comprehensive income 0 0  
Total $ 289,000,000 $ 321,000,000  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 5.88% 5.49%  
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Service cost $ 22,000,000 $ 21,000,000 27,000,000
Interest cost 34,000,000 36,000,000 25,000,000
Expected return on plan assets (46,000,000) (46,000,000) (48,000,000)
Amortization of prior service cost (credit) 0 0 0
Amortization of net loss 13,000,000 11,000,000 24,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement [2] 37,000,000 0 38,000,000
Net periodic postretirement benefit cost 60,000,000 22,000,000 66,000,000
Significant Assumptions Used to Measure Costs [Abstract]      
Plan amendments 0 (1,000,000)  
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets 14,000,000 11,000,000  
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation (30,000,000) 16,000,000 (32,000,000)
Net benefit cost recognized for financial reporting $ 30,000,000 $ 38,000,000 $ 34,000,000
Discount rate (as a percent) 5.49% 5.80% 3.08%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase 4.25% 4.25% 3.75%
Expected average long-term rate of return on assets (as a percent) 7.25% 7.25% 6.60%
Postretirement Benefits Plan      
Change in Projected Benefit Obligation [Roll Forward]      
Obligation at Jan. 1 $ 42,000,000 $ 48,000,000  
Service cost 1,000,000 0 $ 0
Interest cost 2,000,000 3,000,000 2,000,000
Actuarial (gain) loss 1,000,000 (2,000,000)  
Benefit payments (5,000,000) (7,000,000)  
Obligation at Dec. 31 41,000,000 42,000,000 48,000,000
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 3,000,000 5,000,000  
Actual return (loss) on plan assets 0 0  
Employer contributions 4,000,000 5,000,000  
Benefit payments (5,000,000) (7,000,000)  
Fair value of plan assets at Dec. 31 2,000,000 [3] 3,000,000 5,000,000
Funded Status of Plans at Dec. 31 [Abstract]      
Funded status (39,000,000) (39,000,000)  
Current liabilities (3,000,000) (2,000,000)  
Noncurrent liabilities (36,000,000) (37,000,000)  
Net postretirement amounts recognized on consolidated balance sheets (39,000,000) (39,000,000)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 14,000,000 15,000,000  
Total 14,000,000 15,000,000  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]      
Noncurrent regulatory assets 13,000,000 14,000,000  
Net-of-tax accumulated other comprehensive income 1,000,000 1,000,000  
Total $ 14,000,000 $ 15,000,000  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 5.88% 5.54%  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 7.00% 6.50%  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65 7.50% 5.50%  
Ultimate health care trend assumption rate (as a percent) 4.50% 4.50%  
Period until ultimate trend rate is reached (in years) $ 9 $ 6  
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Service cost 1,000,000 0 0
Interest cost 2,000,000 3,000,000 2,000,000
Expected return on plan assets 0 0 0
Amortization of prior service cost (credit) 0 (1,000,000) (3,000,000)
Amortization of net loss 0 0 1,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement [2] 0 0 0
Net periodic postretirement benefit cost 3,000,000 2,000,000 0
Significant Assumptions Used to Measure Costs [Abstract]      
Plan amendments 0 0  
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets 0 0  
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation 0 0 0
Net benefit cost recognized for financial reporting $ 3,000,000 $ 2,000,000 $ 0
Discount rate (as a percent) 5.54% 5.80% 3.09%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase 0.00% 0.00% 0.00%
Expected average long-term rate of return on assets (as a percent) 5.00% 5.00% 4.10%
[1] See Note 8 for further information regarding fair value measurement inputs and methods.
[2] A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024 and 2022, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $37 million and $38 million, respectively, which was not recognized in earnings due to the effects of regulation. There were no settlement charges recorded for the qualified pension plans in 2023.
[3] See Note 8 for further information on fair value measurement inputs and methods.
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Jan. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Defined Contribution Plan, Administrative Expense     $ 14 $ 14 $ 13
Estimated costs of health plan subsidies - VRP     7 8  
Pension Plan          
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]          
2025     63    
2026     59    
2027     58    
2028     56    
2029     57    
2030-2034     269    
Pension Plan | Xcel Energy [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits     100 50 50
Pension Plan | Xcel Energy [Member] | Subsequent Event          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits $ 125        
Pension Plan | NSP Minnesota [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits     41 23 5
Pension Plan | NSP Minnesota [Member] | Subsequent Event          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits $ 54        
Postretirement Benefits Plan          
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]          
2025 [1]     5    
2026 [1]     5    
2027 [1]     4    
2028 [1]     4    
2029 [1]     4    
2030-2034 [1]     15    
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits     11 11 13
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member] | Subsequent Event          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits   $ 8      
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits     $ 4 $ 5 $ 7
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member] | Subsequent Event          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits   $ 5      
[1] Amount is reported net of expected Medicare Part D subsidies, which are immaterial
v3.25.0.1
Benefit Plans and Other Postretirement Benefits, Voluntary Retirement Program (Details)
 12 Months Ended
Dec. 31, 2024
Voluntary Retirement Program [Line Items]  
Voluntary Retirement Program, Significant Assumptions to Measure Benefit Obligation
Significant Assumptions to Measure Benefit Obligations:20242023
Discount rate for year-end valuation5.00 %5.50 %
Mortality tablePRI-2012PRI-2012
Health care costs trend rate7.00 %7.00 %
Ultimate trend assumption4.50 %N/A
Years until ultimate trend is reached9N/A
v3.25.0.1
Commitments and Contingencies Sherco (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
May 17, 2024
Commitments and Contingencies Disclosure [Abstract]    
ALJ Recommended Customer Refund   $ 34
Disallowance Not Considered in ALJ Recommendation   $ 22
2011 Sherco Unit 3 Outage Refunds $ 47  
v3.25.0.1
Commitments and Contingencies MGP Sites (Details) - Other MGP, Landfill, or Disposal Sites
Dec. 31, 2024
USD ($)
Loss Contingencies [Line Items]  
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation 7
Cost of identified MGP, landfill, or disposal sites under current investigation and/or remediation $ 1,000,000
v3.25.0.1
Commitments and Contingencies Environmental Requirements - Water and Waste (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Loss Contingencies [Line Items]  
Legacy CCR Investigation and Remediation Costs $ 6
Cost of Coal Ash Removal Projects 60
Federal Clean Water Act Section 316 (b) [Member] | Capital Addition Purchase Commitments [Member]  
Loss Contingencies [Line Items]  
Liability for estimated cost to comply with regulation $ 45
v3.25.0.1
Commitment and Contingencies AROs (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance $ 2,658 $ 2,727
Amounts Incurred (61) [1] (10) [2]
Amounts Settled (6) (1)
Accretion 128 126
Cash flow revisions 232 [3] (204) [4]
Ending balance 3,073 2,658
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member]    
Other Commitments [Line Items]    
Legally restricted assets, for purposes of funding future nuclear decommissioning 3,494 [5] 3,211 [6]
Fair Value, Measurements, Recurring | Nuclear Decommissioning Fund [Member] | Estimate of Fair Value Measurement [Member]    
Other Commitments [Line Items]    
Legally restricted assets, for purposes of funding future nuclear decommissioning 3,500 3,200
Electric Plant Nuclear Production Decommissioning    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 2,107 2,160
Amounts Incurred 0 [1] 0 [2]
Amounts Settled 0 0
Accretion 106 105
Cash flow revisions 263 [3] (158) [4]
Ending balance 2,476 2,107
Electric Plant Wind Production    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 424 416
Amounts Incurred 0 [1] (10) [2]
Amounts Settled 0 0
Accretion 15 15
Cash flow revisions (33) [3] (17) [4]
Ending balance 406 424
Electric Plant Steam Production Ash Containment    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 77 75
Amounts Incurred (61) [1] 0 [2]
Amounts Settled   (1)
Accretion 4 3
Cash flow revisions 3 [3] 0 [4]
Ending balance 139 77
Electric Plant Electric Distribution    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 17 16
Amounts Incurred 0 [1] 0 [2]
Amounts Settled 0 0
Accretion 1 1
Cash flow revisions 0 [3] 0 [4]
Ending balance 18 17
Natural Gas Plant Gas Transmission and Distribution    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 32 59
Amounts Incurred 0 [1] 0 [2]
Amounts Settled 0 0
Accretion 2 2
Cash flow revisions (1) [3] (29) [4]
Ending balance 33 32
Common and Other Property Common Miscellaneous    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 1 1
Amounts Incurred 0 [1] 0 [2]
Amounts Settled 0 0
Accretion 0 0
Cash flow revisions 0 [3] 0 [4]
Ending balance 1 $ 1
Electric Plant Steam and Other Production Asbestos    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Amounts Settled $ (6)  
[1] Amounts incurred pertain to CCR coal ash regulations and Sherco Solar 1 being placed in service.
[2] Amounts incurred relate to the Northern Wind farm placed in service.
[3] In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes in the nuclear AROs were driven by updated assumptions in the nuclear triennial filing coupled with discount rate and escalation rate changes. Wind, steam, and other production AROs were revised due to the results of 2024 dismantling studies.
[4] In 2023, AROs were revised for changes in timing and estimates of cash flows. Changes in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were changes to inflation and discount rate assumptions as well as updated mileage of gas lines and number of services.
[5] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.
[6] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.
v3.25.0.1
Indeterminate AROs (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
Indeterminate Costs Incurred, Asset Retirement Obligation Due to Asbestos $ 0
v3.25.0.1
Commitments and Contingencies, Nuclear Insurance (Details) - Nuclear Insurance
$ in Millions
 12 Months Ended
Dec. 31, 2024
USD ($)
Reactor
Nuclear Insurance [Abstract]  
Nuclear insurance coverage secured for the Company's public liability exposure $ 500
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program 15,800
Maximum assessments per reactor per accident $ 166
Number of owned and licensed reactors | Reactor 3
Maximum funding requirement per reactor for any one year $ 25
Maximum assessments for business interruption insurance each calendar year 19
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year 34
Maximum  
Nuclear Insurance [Abstract]  
Loss Contingency, Estimate of Possible Loss 16,300
Insurance coverage limits for NSP-Minnesota's nuclear plant sites 2,800
Maximum | NSP Minnesota [Member]  
Nuclear Insurance [Abstract]  
Business Interruption Insurance Coverage Provided by NEIL 490
Business Interruption Insurance Coverage Provided by NEIL - Prairie Island $ 420
v3.25.0.1
Commitments and Contingencies Nuclear Fuel Disposal (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Canister
Dec. 31, 2023
USD ($)
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring    
Loss Contingencies [Line Items]    
Decommissioning Fund Investments | $ $ 3,494 [1] $ 3,211 [2]
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Nuclear Decommissioning Fund [Member]    
Loss Contingencies [Line Items]    
Decommissioning Fund Investments | $ $ 3,500 3,200
NSP Minnesota [Member]    
Loss Contingencies [Line Items]    
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds 100.00%  
NSP Minnesota [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring    
Loss Contingencies [Line Items]    
Decommissioning Fund Investments | $ $ 3,500 $ 3,200
Monticello [Member]    
Loss Contingencies [Line Items]    
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility | Canister 30  
Prairie Island [Member]    
Loss Contingencies [Line Items]    
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility | Canister 52  
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility | Canister 64  
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.
[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.
v3.25.0.1
Commitments and Contingencies Regulatory Plant Decommissioning Recovery (Details) - USD ($)
$ in Millions
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]      
Asset Retirement Obligation $ 3,073 $ 2,658 $ 2,727
NSP Minnesota [Member]      
Public Utilities, General Disclosures [Line Items]      
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds 100.00%    
Nuclear Plant [Member]      
Public Utilities, General Disclosures [Line Items]      
Asset Retirement Obligation $ 2,476 2,107 $ 2,160
Fair Value Measured on a Recurring Basis | Estimate of Fair Value Measurement [Member]      
Public Utilities, General Disclosures [Line Items]      
Decommissioning Fund Investments 3,494 [1] 3,211 [2]  
Fair Value Measured on a Recurring Basis | Estimate of Fair Value Measurement [Member] | NSP Minnesota [Member]      
Public Utilities, General Disclosures [Line Items]      
Decommissioning Fund Investments 3,500 3,200  
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Estimate of Fair Value Measurement [Member]      
Public Utilities, General Disclosures [Line Items]      
Decommissioning Fund Investments $ 3,500 $ 3,200  
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $54 million of other miscellaneous investments.
[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments.
v3.25.0.1
Commitments and Contingencies, Leases (Details) - USD ($)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Lessee, Lease, Description [Line Items]      
Maximum Length - Short-Term Leases 12 months    
Operating Lease, Weighted Average Discount Rate, Percent 4.70%    
Operating Lease, Assets and Liabilities, Lessee [Abstract]      
Operating Lease, Right-of-Use Asset, Gross $ 875,000,000 $ 834,000,000  
Operating Lease, Right-of-Use Asset, Accumulated Depreciation (482,000,000) (395,000,000)  
Operating lease right-of-use assets 393,000,000 439,000,000  
Lease, Cost [Abstract]      
Operating Lease, Cost [1] 111,000,000 113,000,000 $ 107,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]      
2025 114,000,000    
2026 102,000,000    
2027 85,000,000    
2028 53,000,000    
2029 12,000,000    
Thereafter 195,000,000    
Total minimum obligation 561,000,000    
Interest component of obligation (147,000,000)    
Operating Lease, Liability 414,000,000    
Less current portion (97,000,000) (91,000,000)  
Operating lease liabilities 317,000,000 372,000,000  
Weighted Average Remaining lease term, operating 11.9    
Property, Plant and Equipment, Other Types [Member]      
Operating Lease, Assets and Liabilities, Lessee [Abstract]      
Operating Lease, Right-of-Use Asset, Gross 166,000,000 125,000,000  
Lease, Cost [Abstract]      
Operating Lease, Cost [2] 15,000,000 13,000,000 9,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]      
2025 13,000,000    
2026 13,000,000    
2027 13,000,000    
2028 13,000,000    
2029 12,000,000    
Thereafter 195,000,000    
Total minimum obligation 259,000,000    
Interest component of obligation (125,000,000)    
Operating Lease, Liability 134,000,000    
Purchased Power Agreements      
Operating Lease, Assets and Liabilities, Lessee [Abstract]      
Operating Lease, Right-of-Use Asset, Gross 709,000,000 709,000,000  
Lease, Cost [Abstract]      
Operating Lease, Cost 96,000,000 $ 100,000,000 $ 98,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]      
2025 [3],[4] 101,000,000    
2026 [3],[4] 89,000,000    
2027 [3],[4] 72,000,000    
2028 [3],[4] 40,000,000    
2029 [3],[4] 0    
Thereafter [3],[4] 0    
Total minimum obligation [3],[4] 302,000,000    
Interest component of obligation [3],[4] (22,000,000)    
Operating Lease, Liability [3],[4] $ 280,000,000    
[1] 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.
[2] Includes immaterial short-term lease expense for 2024, 2023 and 2022.
[3] Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
[4] PPA operating leases contractually expire at various dates through 2039.
v3.25.0.1
Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Energy      
Purchased Power Agreements (PPAs) [Abstract]      
Purchased power expense $ 186 $ 185 $ 182
Estimated Future Payments Under PPAs [Abstract]      
2025 [1] 53    
2026 [1] 21    
2027 [1] 21    
2028 [1] 22    
2029 [1] 22    
Thereafter [1] 0    
Total [1],[2] 139    
Capacity      
Purchased Power Agreements (PPAs) [Abstract]      
Purchased power expense 64 $ 62 $ 60
Estimated Future Payments Under PPAs [Abstract]      
2025 32    
2026 15    
2027 13    
2028 6    
2029 6    
Thereafter 2    
Total [2] $ 74    
[1] Excludes contingent energy payments for renewable energy PPAs.
[2] Includes amounts allocated to NSP-Wisconsin through intercompany charges.
v3.25.0.1
Commitments and Contingencies, Fuel Contracts (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Coal  
Fuel Contracts [Abstract]  
2025 $ 104
2026 40
2027 4
2028 0
2029 0
Thereafter 0
Total 148 [1]
Nuclear Fuel  
Fuel Contracts [Abstract]  
2025 168
2026 62
2027 133
2028 19
2029 67
Thereafter 49
Total 498 [1]
Natural Gas Supply  
Fuel Contracts [Abstract]  
2025 84
2026 0
2027 0
2028 0
2029 0
Thereafter 0
Total 84 [1]
Natural Gas Storage and Transportation  
Fuel Contracts [Abstract]  
2025 141
2026 140
2027 108
2028 41
2029 21
Thereafter 29
Total $ 480 [1]
[1] Includes amounts allocated to NSP-Wisconsin through interchange billings.
v3.25.0.1
Commitments and Contingencies, Variable Interest Entities (Details) - MW
Dec. 31, 2024
Dec. 31, 2023
Purchased Power Agreements [Abstract]    
Generating capacity (in MW) 1,347 1,347
v3.25.0.1
Commitments and Contingencies - Fuel Clause Adjustment (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
Proposed Refund - 2023 FCA $ 22
v3.25.0.1
Other Comprehensive Income (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Accumulated other comprehensive loss at Jan. 1 $ 8,207  
Accumulated other comprehensive (loss) income at end of period 9,272 $ 8,207
Gains and Losses on Cash Flow Hedges    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Accumulated other comprehensive loss at Jan. 1 (18) (16)
Net current period other comprehensive income   (2)
Accumulated other comprehensive (loss) income at end of period (6) (18)
Other comprehensive income (loss) before reclassifications 12 (3)
Gains and Losses on Cash Flow Hedges | Interest Rate Swap [Member]    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Amortization of interest rate hedges [1]   (1)
Defined Benefit Pension and Postretirement Items    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Accumulated other comprehensive loss at Jan. 1 (2) (2)
Net current period other comprehensive income   0
Accumulated other comprehensive (loss) income at end of period (2) (2)
Other comprehensive income (loss) before reclassifications 0 0
Defined Benefit Pension and Postretirement Items | Interest Rate Swap [Member]    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Amortization of interest rate hedges   0
Total    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Accumulated other comprehensive loss at Jan. 1 (20) (18)
Net current period other comprehensive income   (2)
Accumulated other comprehensive (loss) income at end of period (8) (20)
Other comprehensive income (loss) before reclassifications $ 12 (3)
Total | Interest Rate Swap [Member]    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Amortization of interest rate hedges   $ (1)
[1] Included in interest charges.
v3.25.0.1
Segments and Related Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting Information [Line Items]      
Natural gas $ 653 $ 754 $ 1,022
Revenues Including Intersegment Revenues 5,764 5,998 6,642
Other 15 48 45
Total operating revenues 5,767 6,043 6,684
Depreciation and amortization 1,106 981 1,014
Total interest charges and financing costs 337 304 279
Income tax benefit (356) (109) (112)
Net income (loss) 793 707 675
Related Party Transaction - Electric Domestic Regulated Revenue 460 493  
Electric fuel and purchased power 1,988 2,069 2,416
Cost of natural gas sold and transported 295 466 741
Operating and maintenance expenses 1,271 1,244 1,228
Other income (expense), net 11 0 (7)
Regulated Natural Gas      
Segment Reporting Information [Line Items]      
Revenues Including Intersegment Revenues 664 756 1,024
All Other      
Segment Reporting Information [Line Items]      
Net income (loss) 28 21 4
Regulated Electric Segment      
Segment Reporting Information [Line Items]      
Revenues Including Intersegment Revenues 5,100 5,242 5,618
Total revenues      
Segment Reporting Information [Line Items]      
Depreciation and amortization 1,105 980 1,013
Total interest charges and financing costs 337 304 279
Income tax benefit (365) (117) (113)
Net income (loss) 765 686 671
Regulated Operating Revenue (5,752) [1] (5,995) [2] (6,639)
Electric fuel and purchased power 1,988 2,069 2,416
Cost of natural gas sold and transported 295 466 741
Operating and maintenance expenses 1,285 1,251 1,220
Other income (expense), net 354 359 [3] 415
Total revenues | Regulated Natural Gas      
Segment Reporting Information [Line Items]      
Natural gas 653 [1] 754 [2] 1,022
Depreciation and amortization 80 71 60
Total interest charges and financing costs 30 26 22
Income tax benefit 25 10 14
Net income (loss) 77 38 45
Electric fuel and purchased power 0 0 0
Cost of natural gas sold and transported 295 466 741
Operating and maintenance expenses 104 98 94
Other income (expense), net 53 47 [3] 48
Total revenues | All Other      
Segment Reporting Information [Line Items]      
Other 15 48 45
Total revenues | Regulated Electric Segment      
Segment Reporting Information [Line Items]      
Operating revenue, Regulated Electric 5,099 [1] 5,241 [2] 5,617 [4]
Depreciation and amortization 1,025 909 953
Total interest charges and financing costs 307 278 257
Income tax benefit (390) (127) (127)
Net income (loss) 688 648 626
Electric fuel and purchased power 1,988 2,069 2,416
Cost of natural gas sold and transported 0 0 0
Operating and maintenance expenses 1,181 1,153 1,126
Other income (expense), net 301 312 [3] 367
Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Regulated Operating Revenue (12) (3) (3)
Intersegment Eliminations | Regulated Natural Gas      
Segment Reporting Information [Line Items]      
Natural gas 11 2 2
Intersegment Eliminations | Regulated Electric Segment      
Segment Reporting Information [Line Items]      
Operating revenue, Regulated Electric $ 1 $ 1 $ 1
[1] Regulated electric results include $460 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.
[2] Regulated electric results include $493 million of affiliate revenues. Regulated natural gas results include $1 million of affiliate revenues. See Note 13 for further information.
[3] Other segment expenses, net, for 2023 additionally includes workforce reduction expenses.
[4] Regulated electric results include $514 million of affiliate revenues. See Note 13 for further information.
v3.25.0.1
Related Party Transactions (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
NSP-Wisconsin      
Operating expenses      
Other Receivables $ 0 $ 9  
Accounts payable to affiliates 28 0  
PSCo      
Operating expenses      
Other Receivables 0 5  
Accounts payable to affiliates 7 0  
SPS      
Operating expenses      
Other Receivables 0 0  
Accounts payable to affiliates 2 4  
Other subsidiaries of Xcel Energy Inc.      
Operating expenses      
Other Receivables 1 1  
Accounts payable to affiliates 63 85  
Xcel Energy [Member]      
Operating expenses      
Other Receivables 1 15  
Accounts payable to affiliates 100 89  
Purchased Power      
Operating expenses      
Costs and Expenses, Related Party 65 63 $ 70
Transmission Expense      
Operating expenses      
Costs and Expenses, Related Party 151 142 132
Other Expense      
Operating expenses      
Costs and Expenses, Related Party 710 719 673
Interest Expense      
Operating expenses      
Costs and Expenses, Related Party 2 5 1
Electricity, US Regulated | Xcel Energy [Member]      
Operating expenses      
Interest and Other Income 5 1 1
Revenues 460 493 514
Natural Gas, US Regulated | Xcel Energy [Member]      
Operating expenses      
Revenues $ 1 $ 1 $ 0
v3.25.0.1
Compensation Related Costs, Postemployment Benefits (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
USD ($)
Employees
Xcel Energy [Member]  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Other Postretirement Benefits Cost (Reversal of Cost) | $ $ 72
NSP Minnesota [Member]  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Other Postretirement Benefits Cost (Reversal of Cost) | $ $ 32
Voluntary Retirement Program | Xcel Energy [Member]  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Entity Number of Employees | Employees 400
Employee Severance | Xcel Energy [Member]  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Entity Number of Employees | Employees 150
v3.25.0.1
Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Jan. 1 $ 48 $ 46 $ 45
Charged to costs and expenses 21 30 21
Charged to other accounts [1] 7 6 6
Deductions from reserves [2] (34) (34) (26)
Balance at Dec. 31 $ 42 $ 48 $ 46
[1] Recovery of amounts previously written-off.
[2] Deductions related primarily to bad debt write-offs.