Northern States Power 10-K 21 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 21, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0
Document Information [Line Items]
Document Financial Statement Error Correction [Flag]	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Firm ID	34
Auditor Location	Minneapolis, Minnesota

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating revenues
Electric, non-affiliates	$ 4,748	$ 5,103	$ 4,593
Electric, affiliates	493	514	501
Natural gas	754	1,022	623
Other	48	45	39
Total operating revenues	6,043	6,684	5,756
Operating expenses
Electric fuel and purchased power	2,069	2,416	2,042
Cost of natural gas sold and transported	466	741	385
Cost of sales — other	30	26	23
Operating and maintenance expenses	1,244	1,228	1,190
Conservation program expenses	118	163	144
Depreciation and amortization	981	1,014	926
Taxes (other than income taxes)	237	276	264
Workforce reduction expenses	32	0	0
Total operating expenses	5,177	5,864	4,974
Operating income	866	820	782
Other (expense) income, net	0	(7)	4
Allowance for funds used during construction — equity	36	29	30
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8 and $8, respectively	325	291	271
Allowance for funds used during construction — debt	(21)	(12)	(13)
Total interest charges and financing costs	304	279	258
Income before income taxes	598	563	558
Income tax benefit	(109)	(112)	(48)
Net income	$ 707	$ 675	$ 606

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Other financing costs	$ 8	$ 8	$ 8

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Comprehensive income:
Net income	$ 707	$ 675	$ 606
Derivative instruments:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification and Tax	(3)	0	0
Other Comprehensive Income (Loss), Net Investment Hedge, Gain (Loss), Reclassification, before Tax	1	1	2
Total other comprehensive (loss) income	(2)	2	2
Total comprehensive income	705	677	608
Net pension and retiree medical gain arising during the period, net of tax	$ 0	$ 1	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net income	$ 707	$ 675	$ 606
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	988	1,021	932
Nuclear fuel amortization	96	118	114
Deferred income taxes	214	(214)	(36)
Allowance for equity funds used during construction	(36)	(29)	(30)
Provision for bad debts	30	21	24
Changes in operating assets and liabilities:
Accounts receivable	1	(102)	(89)
Accrued unbilled revenues	82	(53)	(71)
Inventories	(27)	(85)	(22)
Other current assets	(19)	(4)	3
Accounts payable	(64)	46	69
Net regulatory assets and liabilities	287	443	(282)
Other current liabilities	56	39	(5)
Pension and other employee benefit obligations	(15)	(11)	(41)
Other, net	1	6	(50)
Net cash provided by operating activities	2,301	1,871	1,122
Investing activities
Capital/construction expenditures	(2,282)	(1,901)	(1,866)
Purchase of investment securities	(994)	(1,332)	(757)
Proceeds from the sale of investment securities	959	1,297	743
Investments in utility money pool arrangement	(300)	(1,522)	(821)
Repayments from utility money pool arrangement	243	1,613	730
Other, net	(3)	6	1
Net cash used in investing activities	(2,377)	(1,839)	(1,970)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(42)	207	(179)
Borrowings under utility money pool arrangement	302	6	434
Repayments under utility money pool arrangement	(302)	(6)	(434)
Proceeds from issuance of long-term debt	783	489	836
Repayment of long-term debt	(400)	(300)	0
Capital contributions from parent	351	124	649
Dividends paid to parent	(647)	(560)	(431)
Net cash provided by (used in) financing activities	45	(40)	875
Net change in cash, cash equivalents and restricted cash	(31)	(8)	27
Cash, cash equivalents and restricted cash at beginning of period	65	73	46
Cash, cash equivalents and restricted cash at end of period	34	65	73
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(294)	(268)	(245)
Cash received (paid) for income taxes, net	256	(100)	11
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	218	208	242
Inventory transfers to property, plant and equipment	55	10	8
Operating lease right-of-use assets	216	1	4
Allowance for equity funds used during construction	$ 36	$ 29	$ 30

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash, cash equivalents and restricted cash at end of period		$ 34	$ 65
Investments in money pool arrangements		57	0
Accrued unbilled revenues		290	372
Inventories		356	384
Regulatory assets		250	384
Derivative instruments		50	89
Prepayments and other		87	62
Total current assets		1,629	1,935
Property, plant and equipment, net		18,757	17,478
Other assets
Nuclear decommissioning fund and other investments		3,262	2,930
Regulatory assets		837	894
Derivative instruments		61	68
Operating lease right-of-use assets		439	324
Other		16	29
Total other assets		4,615	4,245
Total assets		25,001	23,658
Current liabilities
Current portion of long-term debt		0	400
Short-term debt		165	207
Regulatory liabilities	[1]	300	191
Taxes accrued		223	272
Accrued interest		79	79
Dividends payable to parent		121	122
Derivative instruments		44	42
Operating lease liabilities		91	98
Other		351	227
Total current liabilities		2,042	2,346
Deferred credits and other liabilities
Deferred income taxes		1,992	1,666
Deferred investment tax credits		14	15
Regulatory liabilities	[1]	2,097	1,983
Asset retirement obligations		2,658	2,727
Derivative instruments		86	102
Pension and employee benefit obligations		168	155
Operating lease liabilities		372	256
Other		35	30
Total deferred credits and other liabilities		7,422	6,934
Commitments and contingencies
Capitalization
Long-term debt		7,330	6,542
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		$ 5,686	$ 5,374
Retained earnings		2,541	2,480
Accumulated other comprehensive loss		(20)	(18)
Total common stockholder's equity		8,207	7,836
Total liabilities and equity		25,001	23,658
Related Party
Current assets
Accounts receivable, net		15	45
Current liabilities
Accounts payable		89	89
Affiliated Entity
Current assets
Accounts receivable, net		490	534
Current liabilities
Accounts payable		$ 579	$ 619
[1] Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities.

CONSOLIDATED STATEMENTS OF COMM

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, 2020		1,000,000
Balance at beginning of period at Dec. 31, 2020	$ 6,769	$ 0	$ 4,585	$ 2,206	$ (22)
Increase (Decrease) in Stockholder's Equity
Net income	606			606
Other comprehensive income	2				2
Dividends declared to parent	(421)			(421)
Contribution of capital by parent	617		617
Balance at end of period (shares) at Dec. 31, 2021		1,000,000
Balance at end 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	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)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
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. 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 or to systems required by various state regulatory commissions. 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, 2023 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 (expense) income, 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 3.7% for 2023, 4.0% for 2022 and 3.7% for 2021. 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 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 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. 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 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, 2023 and 2022, the allowance for bad debts was $48 million and $46 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, 2023 Dec. 31, 2022 Inventories Materials and supplies $ 219 $ 200 Fuel 105 103 Natural gas 32 81 Total inventories $ 356 $ 384 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 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.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
Accounting Pronouncements	Recently Issued Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures , which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and NSP-Minnesota does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures

Property Plant and Equipment Pr

Property Plant and Equipment Property Plant and Equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Property, plant and equipment, net Electric plant $ 21,206 $ 20,114 Natural gas plant 2,256 2,100 Common and other property 1,301 1,156 Plant to be retired (a) 604 646 CWIP 1,085 907 Total property, plant and equipment 26,452 24,923 Less accumulated depreciation (8,044) (7,734) Nuclear fuel 3,337 3,183 Less accumulated amortization (2,988) (2,894) Property, plant and equipment, net $ 18,757 $ 17,478 (a) Sherco 2 retired in December 2023. Amounts include Sherco 1 and 3 and A.S. King for 2023 and Sherco Units 1, 2 and 3 and A.S. King for 2022. Balance is presented net of accumulated depreciation. Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2023: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned Electric generation: Sherco Unit 3 $ 633 $ 480 59 % Sherco common facilities 185 121 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 4 50 Huntley Wilmarth 49 2 50 CapX2020 820 141 51 Total (a) $ 1,703 $ 752 (a) Projects additionally include $2 million in CWIP. NSP-Minnesota’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2023
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 Period Dec. 31, 2023 Dec. 31, 2022 (a) Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 18 $ 340 $ 12 $ 347 Recoverable deferred taxes on AFUDC Plant lives — 127 — 112 Excess deferred taxes — TCJA 7 Various 8 96 10 103 Deferred natural gas and electric energy/fuel costs One three 16 58 110 65 PI extended power uprate 11 years 4 38 4 42 Benson biomass PPA termination and asset purchase Five 10 36 10 45 MISO capacity revenue tracker One two 36 26 — — Contract valuation adjustments (b) 1, 8 Term of related contract 9 22 16 28 Purchased power contracts costs Term of related contract 1 20 7 19 Conservation programs (c) 1 One two 6 19 6 19 Nuclear refueling outage costs 1 One two 43 19 30 12 Losses on reacquired debt Term of related debt 1 9 1 10 Sales true-up and revenue decoupling One two 7 2 53 — Renewable resources and environmental initiatives Less than one 38 — 50 — Gas pipeline inspection and remediation costs Less than one 37 — 42 — Net AROs (d) 1, 10 N/A — — — 62 Other Various 16 25 33 30 Total regulatory assets $ 250 $ 837 $ 384 $ 894 (a) Prior period amounts have been reclassified to conform with current year presentation. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d) The 2022 amount is net the nuclear decommissioning accruals and gains from decommissioning investments. In 2023 the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2023 Dec. 31, 2022 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 5 $ 1,157 $ 6 $ 1,200 Plant removal costs 1, 10 Various — 741 — 693 Net AROs (b) Various — 90 — — Renewable resources and environmental initiatives Various 9 27 6 19 Sales true-up and revenue decoupling One two 18 13 — 22 ITC deferrals 1 Various — 13 — 17 Formula rates One two 8 9 6 9 Deferred natural gas and electric energy/fuel costs Less than one 143 — 26 — Conservation programs Less than one 27 — 42 — Contract valuation adjustments (c) 1, 8 Less than one 16 — 56 — DOE Settlement Less than one 15 — — — Other Various 59 47 49 23 Total regulatory liabilities (d) $ 300 $ 2,097 $ 191 $ 1,983 (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 the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (d) Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. NSP-Minnesota’s regulatory assets not earning a return include past expenditures of $479 million and $369 million, respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.

Borrowings and Other Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2023
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, 2023 Year Ended Dec. 31 2023 2022 2021 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — — Average amount outstanding 21 17 — 6 Maximum amount outstanding 113 135 4 236 Weighted average interest rate, computed on a daily basis 5.34 % 4.97 % 3.87 % 0.07 % Weighted average interest rate at period end N/A N/A N/A N/A Commercial Paper — Commercial paper outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2023 Year Ended Dec. 31 2023 2022 2021 Borrowing limit $ 700 $ 700 $ 700 $ 500 Amount outstanding at period end 165 165 207 — Average amount outstanding 112 92 21 26 Maximum amount outstanding 265 441 290 317 Weighted average interest rate, computed on a daily basis 5.47 % 4.99 % 4.14 % 0.18 % Weighted average interest rate at end of period 5.47 5.47 4.64 N/A Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2023 and 2022, there were $15 million of letters of credit outstanding under the credit facility. 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) 2023 2022 47.7 % 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, 2023, NSP-Minnesota was in compliance with all financial covenants on its debt agreements. NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2023 (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 700 $ 180 $ 520 (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, 2023 and 2022. Bilateral Credit Agreement — In April 2022, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2023, and 2022 NSP-Minnesota had $65 million and $54 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 Instrument Interest Rate Maturity Date 2023 2022 First mortgage bonds 2.60 % May 15, 2023 $ — $ 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds 2.25 April 1, 2031 425 425 First mortgage bonds 5.25 July 15, 2035 250 250 First mortgage bonds 6.25 June 1, 2036 400 400 First mortgage bonds 6.20 July 1, 2037 350 350 First mortgage bonds 5.35 Nov. 1, 2039 300 300 First mortgage bonds 4.85 Aug. 15, 2040 250 250 First mortgage bonds 3.40 Aug. 15, 2042 500 500 First mortgage bonds 4.125 May 15, 2044 300 300 First mortgage bonds 4.00 Aug. 15, 2045 300 300 First mortgage bonds 3.60 May 15, 2046 350 350 First mortgage bonds 3.60 Sept. 15, 2047 600 600 First mortgage bonds 2.90 March 1, 2050 600 600 First mortgage bonds 2.60 June 1, 2051 700 700 First mortgage bonds 3.20 April 1, 2052 425 425 First mortgage bonds (a) 4.50 June 1, 2052 500 500 First mortgage bonds (b) 5.10 May 15, 2053 800 — Other long-term debt 2 3 Unamortized discount (49) (45) Unamortized debt issuance cost (73) (66) Current maturities — (400) Total long-term debt $ 7,330 $ 6,542 (a) 2022 financing. (b) 2023 financing. Maturities of long-term debt are as follows: (Millions of Dollars) 2024 $ — 2025 250 2026 — 2027 — 2028 150 Deferred Financing Costs — Deferred financing costs of approximately $73 million and $66 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2023 and 2022, respectively. 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 fro`m 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, 2023: Equity to Total Capitalization Ratio Equity to Total Capitalization Ratio Actual Low High 2023 47.2 % 57.6 % 52.3 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1,508 million $ 15,702 million $ 16,140 million

Revenues

Revenues	12 Months Ended
	Dec. 31, 2023
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, 2023 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,524 $ 368 $ 41 $ 1,933 C&I 2,298 309 — 2,607 Other 34 — 7 41 Total retail 3,856 677 48 4,581 Wholesale 354 — — 354 Transmission 263 — — 263 Interchange 493 — — 493 Other — 18 — 18 Total revenue from contracts with customers 4,966 695 48 5,709 Alternative revenue and other 275 59 — 334 Total revenues $ 5,241 $ 754 $ 48 $ 6,043 Year Ended Dec. 31, 2022 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,463 $ 510 $ 38 $ 2,011 C&I 2,376 433 — 2,809 Other 38 — 7 45 Total retail 3,877 943 45 4,865 Wholesale 668 — — 668 Transmission 287 — — 287 Interchange 514 — — 514 Other 15 19 — 34 Total revenue from contracts with customers 5,361 962 45 6,368 Alternative revenue and other 256 60 — 316 Total revenues $ 5,617 $ 1,022 $ 45 $ 6,684 Year Ended Dec. 31, 2021 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,374 $ 315 $ 33 $ 1,722 C&I 2,107 246 — 2,353 Other 33 — 6 39 Total retail 3,514 561 39 4,114 Wholesale 442 — — 442 Transmission 242 — — 242 Interchange 501 — — 501 Other 7 14 — 21 Total revenue from contracts with customers 4,706 575 39 5,320 Alternative revenue and other 388 48 — 436 Total revenues $ 5,094 $ 623 $ 39 $ 5,756

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
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: 2023 2022 2021 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 7.0 7.0 7.0 Increases (decreases) in tax from: Wind PTCs (a) (39.5) (39.6) (27.8) Plant regulatory differences (b) (5.7) (6.7) (8.1) Other tax credits, net NOL & tax credit allowances (1.3) (1.3) (1.4) Other, net 0.3 (0.3) 0.7 Effective income tax rate (18.2) % (19.9) % (8.6) % (a) Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income. (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) 2023 2022 2021 Current federal tax (benefit) expense $ (154) $ 70 $ (10) Current state tax expense (benefit) 3 26 (1) Current change in unrecognized tax (benefit) expense (21) 8 1 Deferred federal tax expense (benefit) 5 (237) (87) Deferred state tax expense 51 23 49 Deferred change in unrecognized tax expense 8 — 2 Deferred ITCs (1) (2) (2) Total income tax benefit $ (109) $ (112) $ (48) Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2023 2022 2021 Deferred tax expense (benefit) excluding items below $ 326 $ (283) 109 Adjustments to deferred income taxes for wind production tax credit cash transfers (a) (150) — — Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (114) 70 (145) Tax benefit (expense) allocated to other comprehensive income and other 2 (1) — Deferred tax expense (benefit) $ 64 $ (214) $ (36) (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) 2023 2022 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,938 $ 2,708 Regulatory assets 190 188 Operating lease assets 129 98 Pension expense 64 68 Deferred fuel costs 20 49 Other 9 4 Total deferred tax liabilities $ 3,350 $ 3,115 Deferred tax assets: Tax credit carryforward $ 832 $ 977 Regulatory liabilities 323 324 Operating lease liabilities 129 98 Rate refund 59 28 NOL and tax credit valuation allowances (57) (58) Other employee benefits 31 27 Deferred ITCs 4 5 NOL carryforward — 15 Other 37 33 Total deferred tax assets $ 1,358 $ 1,449 Net deferred tax liability $ 1,992 $ 1,666 (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) 2023 2022 Federal NOL carryforward $ — $ 2 Federal tax credit carryforwards 777 909 Valuation Allowances for federal credit carryforwards (5) — State NOL carryforwards 1 184 Valuation allowances for state NOL carryforwards — (1) State tax credit carryforwards, net of federal detriment (a) 55 68 Valuation allowances for state credit carryforwards, net of federal benefit (b) (52) (58) (a) State tax credit carryforwards are net of federal detriment of $15 million and $18 million as of Dec. 31, 2023 and 2022, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $14 million and $15 million as of Dec. 31, 2023 and 2022, respectively. Federal carryforward periods expire between 2037 and 2043 and state carryforward periods expire starting 2025. 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 - 2016 March 2025 2020 September 2024 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. As of Dec. 31, 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agrees with the report and re-recognized the related benefit in Dec. 2023. State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2023, NSP-Minnesota’s earliest open tax years subject to examination by state taxing authorities under applicable statutes of limitations are as follows: State Tax Year(s) Expiration Minnesota 2014-2016 September 2025 Minnesota 2019 May 2024 In 2020, Minnesota began an audit of tax years 2015-2018. In 2022, the state of Minnesota issued its audit report and in 2023, the Company agreed to the report without any material adjustments. No other state income tax audits are in progress as of Dec. 31, 2023. Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing 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, 2023 Dec. 31, 2022 Unrecognized tax benefit — Permanent tax positions $ 18 $ 31 Unrecognized tax benefit — Temporary tax positions — 3 Total unrecognized tax benefit $ 18 $ 34 Changes in unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Balance at Jan. 1 $ 34 $ 26 $ 24 Additions based on tax positions related to the current year 2 2 2 Additions for tax positions of prior years 1 6 — Reductions for tax positions of prior years (18) — — Reductions for tax positions related to settlements with taxing authorities (1) — — Balance at Dec. 31 $ 18 $ 34 $ 26 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 NOL and tax credit carryforwards $ (18) $ (13) As IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $5 million in the next 12 months. 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) 2023 2022 2021 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (3) $ (2) $ (2) Interest benefit (expense) related to unrecognized tax benefits 4 (1) — Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31 $ 1 $ (3) $ (2) No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2023, 2022 or 2021.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	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 — M ethods 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 $1.2 billion and $1 billion as of Dec. 31, 2023 and 2022, respectively, and unrealized losses were $29 million and $90 million as of Dec. 31, 2023 and 2022, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2023 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 41 $ 41 $ — $ — $ — $ 41 Commingled funds 721 — — — 1,049 1,049 Debt securities 784 — 771 9 — 780 Equity securities 508 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. Dec. 31, 2022 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds 803 — — — 1,178 1,178 Debt securities 738 — 669 6 — 675 Equity securities 406 999 1 — — 1,000 Total $ 1,976 $ 1,028 $ 670 $ 6 $ 1,178 $ 2,882 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments. For the years ended Dec. 31, 2023 and 2022, 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, 2023: Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ 4 $ 261 $ 269 $ 246 $ 780 Rabbi Trusts NSP-Minnesota has established a rabbi trust to provide partial funding for future distributions of its deferred compensation plan. The fair value of assets held in the rabbi trusts were $12 million and $12 million at Dec. 31, 2023 and 2022, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. 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, 2023, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2023, NSP-Minnesota had $150 million of unsettled interest rate derivatives. 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, see Note 11. 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. Derivative instruments 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 December 31, 2023 and 2022 for this purpose relate to FTR instruments administered by MISO. These instruments are intended to offset the impacts of transmission system congestion. Higher congestion costs in recent years have led to an increase in the fair value of FTRs. Settlements of FTRs are shared with electric customers through fuel and purchased energy cost-recovery mechanisms. 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, 2023, 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, 2023 Dec. 31, 2022 MWh of electricity 38 44 MMBtu of natural gas 64 88 (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’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2023, four of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $24 million or 25% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Three of the ten most significant counterparties, comprising $26 million or 27% 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 $45 million or 47% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Five of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, 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, 2023 and 2022, there were $12 million and $4 million, respectively, of derivative liabilities with such underlying contract provisions, respectively. Also, certain contracts may 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, 2023 and 2022, there were approximately $80 million and $76 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. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2023 and 2022. 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 Loss Regulatory (Assets) and Liabilities 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) Natural gas commodity — — Total $ — $ (7) Year Ended Dec. 31, 2021 Other derivative instruments Electric commodity $ — $ 3 Natural gas commodity — (3) Total $ — $ — 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 Loss Regulatory 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 Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 2 (a) $ — $ — Total $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 51 (b) Electric commodity $ — $ (3) (c) $ — Natural gas commodity — 1 (d) (6) (d)(e) Total $ — $ (2) $ 45 (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, 2023, 2022 and 2021. Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2023 Dec. 31, 2022 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 7 $ 32 $ 32 $ 71 $ (42) $ 29 $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 Electric commodity — — 23 23 (7) 16 — — 58 58 (2) 56 Natural gas commodity — 5 — 5 — 5 — 5 — 5 — 5 Total current derivative assets $ 7 $ 37 $ 55 $ 99 $ (49) $ 50 $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 7 $ 43 $ 45 $ 95 $ (34) $ 61 $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 Total noncurrent derivative assets $ 7 $ 43 $ 45 $ 95 $ (34) $ 61 $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 Dec. 31, 2023 Dec. 31, 2022 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Interest rate $ — $ 7 $ — $ 7 $ — $ 7 $ — $ — $ — $ — $ — $ — Other derivative instruments: Commodity trading 6 60 5 71 (43) 28 23 60 6 89 (63) 26 Electric commodity — — 7 7 (7) — — — 2 2 (2) — Natural gas commodity — 3 — 3 — 3 — 2 — 2 — 2 Total current derivative liabilities $ 6 $ 70 $ 12 $ 88 $ (50) 38 $ 23 $ 62 $ 8 $ 93 $ (65) 28 PPAs (b) 6 14 Current derivative instruments $ 44 $ 42 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 14 $ 49 $ 37 $ 100 $ (36) $ 64 $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 Total noncurrent derivative liabilities $ 14 $ 49 $ 37 $ 100 $ (36) 64 $ 37 $ 55 $ 42 $ 134 $ (60) 74 PPAs (b) 22 28 Noncurrent derivative instruments $ 86 $ 102 (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, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $3 million and $6 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) 2023 2022 2021 Balance at Jan. 1 $ 107 $ 56 $ (11) Purchases (a) 98 157 54 Settlements (a) (65) (195) (82) Net transactions recorded during the period: Gains recognized in earnings (b) 15 91 72 Net (losses) gains recognized as regulatory assets and liabilities (a) (104) (2) 23 Balance at Dec. 31 $ 51 $ 107 $ 56 (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 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: 2023 2022 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 7,330 $ 6,561 $ 6,942 $ 5,995 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, 2023 and 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Benefit Plans and Other Postretirement Benefits	Xcel Energy, which includes NSP-Minnesota, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 4.67, 4.86 and 1.96% in 2023, 2022, and 2021, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2023 and 2022 were $12 million and $11 million, respectively, of which $2 million was attributable to NSP-Minnesota in 2023 and 2022, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $2 million in 2023 and $17 million in 2022, respectively, of which immaterial amounts were attributable to NSP-Minnesota. Xcel Energy’s postretirement health care benefit plan is a continuation of certain welfare benefit programs for current employees. A full time employee’s date of hire or a retiree’s date of retirement determine eligibility for each of the programs. Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from investment experts. Xcel Energy and NSP-Minnesota continually review their pension assumptions. Pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2023 were above the assumed level of 7.25%. • Investment returns in 2022 were below the assumed level of 6.60%. • Investment returns in 2021 were above the assumed level of 6.60%. • In 2024, NSP-Minnesota’s expected investment-return assumption is 7.25%. Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year. Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. Plan Assets For each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value: Dec. 31, 2023 (a) Dec. 31, 2022 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 46 $ — $ — $ — $ 46 $ 26 $ — $ — $ — $ 26 Commingled funds 110 — — 265 375 201 — — 201 402 Debt securities — 127 1 — 128 — 129 1 — 130 Equity securities 8 — — — 8 11 — — — 11 Other — 5 — — 5 — 1 — — 1 Total $ 164 $ 132 $ 1 $ 265 $ 562 $ 238 $ 130 $ 1 $ 201 $ 570 (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, 2023 (a) Dec. 31, 2022 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Insurance contracts — — — — — — 1 — — 1 Commingled funds $ — $ — $ — $ 1 $ 1 $ 1 $ — $ — $ 1 $ 2 Debt securities — 2 — — 2 — 2 — — 2 Total $ — $ 2 $ — $ 1 $ 3 $ 1 $ 3 $ — $ 1 $ 5 (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 2023. No assets were transferred in or out of Level 3 for 2022. Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Minnesota are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Change in Benefit Obligation: Obligation at Jan. 1 $ 657 $ 877 $ 48 $ 64 Service cost 21 27 — — Interest cost 36 25 3 2 Plan amendments (1) 1 — — Actuarial (gain) loss 30 (139) (2) (13) Benefit payments (83) (134) (7) (5) Obligation at Dec. 31 $ 660 $ 657 $ 42 $ 48 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 570 $ 853 $ 5 $ 3 Actual return on plan assets 52 (154) — — Employer contributions 23 5 5 7 Benefit payments (83) (134) (7) (5) Fair value of plan assets at Dec. 31 $ 562 $ 570 $ 3 $ 5 Funded status of plans at Dec. 31 $ (98) $ (87) $ (39) $ (43) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (2) $ (1) Noncurrent liabilities (98) (87) (37) (42) Net amounts recognized $ (98) $ (87) $ (39) $ (43) Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2023 2022 2023 2022 Discount rate for year-end valuation 5.49 % 5.80 % 5.54 % 5.80 % Expected average long-term increase in compensation level 4.25 % 4.25 % N/A N/A Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012 Health care costs trend rate — initial: Pre-65 N/A N/A 6.50 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.50 % 5.50 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.50 % 4.50 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.50 % 4.50 % Years until ultimate trend is reached N/A N/A 6 7 Accumulated benefit obligation for the pension plan was $599 million and $600 million as of Dec. 31, 2023 and 2022, respectively. Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income. Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities: Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2021 2023 2022 2021 Service cost $ 21 $ 27 $ 30 $ — $ — $ — Interest cost 36 25 25 3 2 2 Expected return on plan assets (46) (48) (52) — — — Amortization of prior service cost — — — (1) (3) (3) Amortization of net loss 11 24 34 — 1 2 Settlement charge (a) — 38 35 — — — Net periodic pension cost 22 66 72 2 — 1 Effects of regulation 16 (32) (44) — — — Net benefit cost recognized for financial reporting $ 38 $ 34 $ 28 $ 2 $ — $ 1 Significant Assumptions Used to Measure Costs: Discount rate 5.80 % 3.08 % 2.71 % 5.80 % 3.09 % 2.65 % Expected average long-term increase in compensation level 4.25 3.75 3.75 — — — Expected average long-term rate of return on assets 7.25 6.60 6.60 5.00 4.10 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 2022 and 2021, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $38 million and $35 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. Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 321 $ 309 $ 15 $ 16 Prior service credit — — — (1) Total $ 321 $ 309 $ 15 $ 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 $ 11 $ 12 $ — Noncurrent regulatory assets 310 297 14 14 Deferred income taxes — — Net-of-tax accumulated other comprehensive income — 1 1 Total $ 321 $ 309 $ 15 $ 15 Measurement date Dec 31, 2023 Dec 31, 2022 Dec 31, 2023 Dec 31, 2022 Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2021 - 2024 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $100 million in January 2024, of which $41 million is attributable to NSP-Minnesota. • $50 million in 2023, of which $23 million was attributable to NSP-Minnesota. • $50 million in 2022, of which $5 million was attributable to NSP-Minnesota. • $131 million in 2021, of which $34 million was attributable to NSP-Minnesota. The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows: • $11 million expected in 2024, of which $5 million is attributable to NSP-Minnesota. • $11 million during 2023, of which $5 million, was attributable to NSP-Minnesota. • $13 million during 2022, of which $7 million was attributable to NSP-Minnesota. • $15 million during 2021, of which $8 million was attributable to NSP-Minnesota. Targeted asset allocations: Pension Benefits Postretirement Benefits 2023 2022 2023 2022 Long-duration fixed income and interest rate swap securities 38 % 38 % — % — % Domestic and international equity securities 31 33 9 16 Alternative investments 20 18 13 12 Short-to-intermediate fixed income securities 9 9 77 71 Cash 2 2 1 1 Total 100 % 100 % 100 % 100 % The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year Plan Amendments — In 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan. 1, 2024. There were no significant plan amendments made in 2022 which affected the postretirement benefit obligation. In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. Projected Benefit Payments NSP-Minnesota’s projected benefit payments: (Millions of Dollars) Projected Net Projected Postretirement Health Care Benefit Payments (a) 2024 $ 100 $ 5 2025 $ 56 $ 5 2026 $ 56 $ 4 2027 $ 56 $ 4 2028 $ 55 $ 4 2029-2033 $ 273 $ 15 (a) Amount is reported net of expected Medicare Part D subsidies, which are immaterial. Voluntary Retirement Program Incremental to amounts presented above for postretirement benefits, Xcel Energy, which includes NSP-Minnesota, recognized new postemployment costs and obligations in the fourth quarter of 2023 for employees accepted to a voluntary retirement program. Utilizing employee information and the following inputs, the estimated NSP-Minnesota obligations for the program of $8 million for health plan subsidies and $1 million for other medical benefits, each commencing in 2024, were recognized in the fourth quarter of 2023. These unfunded obligations are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheet as of Dec. 31, 2023. Significant Assumptions to Measure Benefit Obligations: 2023 Discount rate for year-end valuation 5.50 % Mortality table PRI-2012 Health care costs trend rate and ultimate trend assumption 7.00 % Defined Contribution Plans Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Minnesota was approximately $14 million, $13 million, and $12 million in 2023, 2022 and 2021, respectively. Multiemployer Plans NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer pension plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
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 January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota responded that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate. 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 2023, NSP-Minnesota and various parties filed recommendations, including the DOC which recommended a $56 million customer refund. The Xcel Large Industrial customer group recommended a refund of $72 million. A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote. MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%. The FERC subsequently issued various related orders related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions. The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial. 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 from final resolution of these issues, however, the 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’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their applicable landfills and surface impoundments. NSP-Minnesota is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. No results above the groundwater protection standards in the rule were identified. 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. Guidelines are also established for allowance banking and emission limit backstops. While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, NSP-Minnesota anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms. NSP-Minnesota has joined other companies in litigation challenging the EPA’s disapproval of Minnesota’s state implementation plan. Currently, the regulation is under a judicial stay for Minnesota and not applicable to NSP-Minnesota pending the outcome of the litigation. AROs — 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 $3.2 billion and $2.9 billion at Dec. 31, 2023 and 2022, respectively. NSP-Minnesota’s AROs were as follows: 2023 (Millions Jan. 1, 2023 Amounts Incurred (a) Amounts Accretion Cash Flow Revisions (b) Dec. 31, 2023 Electric Nuclear $ 2,160 $ — $ — $ 105 $ (158) $ 2,107 Wind 416 10 — 15 (17) 424 Steam and other production 75 — (1) 3 — 77 Distribution 16 — — 1 — 17 Natural gas Transmission and distribution 59 — — 2 (29) 32 Other Miscellaneous 1 — — — — 1 Total liability $ 2,727 $ 10 $ (1) $ 126 $ (204) $ 2,658 (a) Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. (b) In 2023, AROs were revised for changes in timing and estimates of cash flows. 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. 2022 (Millions Jan. 1, 2022 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2022 Electric Nuclear $ 2,056 $ — $ 104 $ — $ 2,160 Wind 384 25 15 (8) 416 Steam and other production 73 — 2 — 75 Distribution 16 — — — 16 Natural gas Transmission and distribution 55 — 2 2 59 Other Miscellaneous 1 — — — 1 Total liability $ 2,585 $ 25 $ 123 $ (6) $ 2,727 (a) Amounts incurred relate to the wind farms placed in service in 2022 (Dakota Range and Rock Aetna). (b) In 2022, AROs were revised for changes in timing and estimates of cash flows. Changes in electric wind AROs were related to the repowering and extended retirement date of Nobles. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage 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, 2023. 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 $16.2 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $450 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. The coverage limits are $2.8 billion for each of NSP-Minnesota’s two nuclear plant sites. 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 $15 million for business interruption insurance and $32 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 4.6%). 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, 2023 Dec. 31, 2022 PPAs $ 709 $ 556 Other 125 78 Gross operating lease ROU assets 834 634 Accumulated amortization (395) (310) Net operating lease ROU assets $ 439 $ 324 Components of lease expense: (Millions of Dollars) 2023 2022 2021 Operating leases PPA capacity payments $ 100 $ 98 $ 96 Other operating leases (a) 13 9 8 Total operating lease expense (b) $ 113 $ 107 $ 104 (a) Includes short-term lease expense o f $2 million, $3 million and $2 million for 2023, 2022 and 2021, respectively. (b) PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. Commitments under operating leases as of Dec. 31, 2023: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2024 $ 99 $ 11 $ 110 2025 101 11 112 2026 89 11 100 2027 72 11 83 2028 40 10 50 Thereafter — 125 125 Total minimum obligation 401 179 580 Interest component of obligation (37) (80) (117) Present value of minimum obligation $ 364 $ 99 463 Less current portion (91) Noncurrent operating lease liabilities $ 372 Weighted-average remaining lease term in years 9.8 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2039. 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 2033, contain minimum energy purchase commitments. Total energy payments on those contracts were $185 million, $182 million and $149 million in 2023, 2022 and 2021, respectively. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $62 million, $60 million and $55 million in 2023, 2022 and 2021, 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, 2023, 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) 2024 $ 63 $ 174 2025 27 53 2026 9 10 2027 8 10 2028 1 10 Thereafter 2 18 Total (b) $ 110 $ 275 (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 2024 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, 2023: (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2024 $ 115 $ 142 $ 88 $ 148 2025 62 179 1 131 2026 21 63 — 128 2027 1 180 — 96 2028 — 50 — 28 Thereafter — 177 — 47 Total (a) $ 199 $ 791 $ 89 $ 578 (a) Includes amounts allocated to NSP-Wisconsin through intercompany charges. 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 and 1,322 MW of capacity under long-term PPAs at Dec. 31, 2023 and 2022, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2039.

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: 2023 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total 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) 2022 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (17) $ (3) $ (20) Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 1 (a) — 1 Net current period other comprehensive income 1 1 2 Accumulated other comprehensive loss at Dec. 31 $ (16) $ (2) $ (18) (a) Included in interest charges.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Segment Information	NSP-Minnesota evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. NSP-Minnesota has the following reportable segments: • Regulated Electric — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Minnesota, North Dakota and South Dakota. 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 — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Minnesota and North Dakota. NSP-Minnesota also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities and revenues associated with processing solid waste into refuse-derived fuel. 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. NSP-Minnesota’s segment information: (Millions of Dollars) 2023 2022 2021 Regulated Electric Operating revenues — external (a) $ 5,241 $ 5,617 $ 5,094 Intersegment revenue 1 1 1 Total revenues $ 5,242 $ 5,618 $ 5,095 Depreciation and amortization 909 953 869 Interest charges and financing costs 278 257 240 Income tax benefit (127) (127) (53) Net income 648 626 566 Regulated Natural Gas Operating revenues — external (b) $ 754 $ 1,022 $ 623 Intersegment revenue 2 2 1 Total revenues $ 756 $ 1,024 $ 624 Depreciation and amortization 71 60 56 Interest charges and financing costs 26 22 18 Income tax expense 10 14 6 Net income 38 45 29 All Other Total revenues $ 48 $ 45 $ 39 Depreciation and amortization 1 1 1 Income tax (benefit) expense 8 1 (1) Net income 21 4 11 Consolidated Total Total revenues (a)(b) $ 6,046 $ 6,687 $ 5,758 Reconciling eliminations (3) (3) (2) Total operating revenues $ 6,043 $ 6,684 $ 5,756 Depreciation and amortization 981 1,014 926 Interest charges and financing costs 304 279 258 Income tax benefit (109) (112) (48) Net income 707 675 606 (a) Operating revenues include $493 million, $514 million and $501 million of affiliate electric revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information. (b)

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2023
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) 2023 2022 2021 Operating revenues: Electric $ 493 $ 514 $ 501 Gas 1 — 1 Operating expenses: Purchased power 63 70 67 Transmission expense 142 132 121 Other operating expenses — paid to Xcel Energy Services Inc. 719 673 615 Interest income 1 1 — Interest expense 5 1 — Accounts receivable and payable with affiliates at Dec. 31: 2023 2022 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 9 $ — $ 4 $ — PSCo 5 — — 2 SPS — 4 — 3 Other subsidiaries of Xcel Energy Inc. 1 85 41 84 $ 15 $ 89 $ 45 $ 89

Compensation Related Costs, Pos

Compensation Related Costs, Postemployment Benefits	12 Months Ended
	Dec. 31, 2023
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.

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2023
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) 2023 2022 2021 Balance at Jan. 1 $ 46 $ 45 $ 33 Additions charged to costs and expenses 30 21 24 Additions charged to other accounts (a) 6 6 5 Deductions from reserves (b) (34) (26) (17) Balance at Dec. 31 $ 48 $ 46 $ 45 (a) Recovery of amounts previously written-off. (b) Deductions related primarily to bad debt write-offs.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
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 or to systems required by various state regulatory commissions. 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. 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, 2023 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 (expense) income, 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 3.7% for 2023, 4.0% for 2022 and 3.7% for 2021. 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 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 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. 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
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.
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, 2023 Dec. 31, 2022 Inventories Materials and supplies $ 219 $ 200 Fuel 105 103 Natural gas 32 81 Total inventories $ 356 $ 384
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 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
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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 Dec. 31, 2022 Inventories Materials and supplies $ 219 $ 200 Fuel 105 103 Natural gas 32 81 Total inventories $ 356 $ 384

Property Plant and Equipment (T

Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Public Utility Property, Plant, and Equipment	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Property, plant and equipment, net Electric plant $ 21,206 $ 20,114 Natural gas plant 2,256 2,100 Common and other property 1,301 1,156 Plant to be retired (a) 604 646 CWIP 1,085 907 Total property, plant and equipment 26,452 24,923 Less accumulated depreciation (8,044) (7,734) Nuclear fuel 3,337 3,183 Less accumulated amortization (2,988) (2,894) Property, plant and equipment, net $ 18,757 $ 17,478 (a)
Schedule of Jointly Owned Utility Plants	Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2023: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned Electric generation: Sherco Unit 3 $ 633 $ 480 59 % Sherco common facilities 185 121 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 4 50 Huntley Wilmarth 49 2 50 CapX2020 820 141 51 Total (a) $ 1,703 $ 752 (a) Projects additionally include $2 million in CWIP.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2023 Dec. 31, 2022 (a) Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 18 $ 340 $ 12 $ 347 Recoverable deferred taxes on AFUDC Plant lives — 127 — 112 Excess deferred taxes — TCJA 7 Various 8 96 10 103 Deferred natural gas and electric energy/fuel costs One three 16 58 110 65 PI extended power uprate 11 years 4 38 4 42 Benson biomass PPA termination and asset purchase Five 10 36 10 45 MISO capacity revenue tracker One two 36 26 — — Contract valuation adjustments (b) 1, 8 Term of related contract 9 22 16 28 Purchased power contracts costs Term of related contract 1 20 7 19 Conservation programs (c) 1 One two 6 19 6 19 Nuclear refueling outage costs 1 One two 43 19 30 12 Losses on reacquired debt Term of related debt 1 9 1 10 Sales true-up and revenue decoupling One two 7 2 53 — Renewable resources and environmental initiatives Less than one 38 — 50 — Gas pipeline inspection and remediation costs Less than one 37 — 42 — Net AROs (d) 1, 10 N/A — — — 62 Other Various 16 25 33 30 Total regulatory assets $ 250 $ 837 $ 384 $ 894 (a) Prior period amounts have been reclassified to conform with current year presentation. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d)
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2023 Dec. 31, 2022 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 5 $ 1,157 $ 6 $ 1,200 Plant removal costs 1, 10 Various — 741 — 693 Net AROs (b) Various — 90 — — Renewable resources and environmental initiatives Various 9 27 6 19 Sales true-up and revenue decoupling One two 18 13 — 22 ITC deferrals 1 Various — 13 — 17 Formula rates One two 8 9 6 9 Deferred natural gas and electric energy/fuel costs Less than one 143 — 26 — Conservation programs Less than one 27 — 42 — Contract valuation adjustments (c) 1, 8 Less than one 16 — 56 — DOE Settlement Less than one 15 — — — Other Various 59 47 49 23 Total regulatory liabilities (d) $ 300 $ 2,097 $ 191 $ 1,983 (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 the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (d) Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities.

Borrowings and Other Financin_2

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Money Pool [Table Text Block]	Money pool borrowings: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2023 Year Ended Dec. 31 2023 2022 2021 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — — Average amount outstanding 21 17 — 6 Maximum amount outstanding 113 135 4 236 Weighted average interest rate, computed on a daily basis 5.34 % 4.97 % 3.87 % 0.07 % Weighted average interest rate at period end N/A N/A N/A N/A
Short Term Debt	Commercial paper outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2023 Year Ended Dec. 31 2023 2022 2021 Borrowing limit $ 700 $ 700 $ 700 $ 500 Amount outstanding at period end 165 165 207 — Average amount outstanding 112 92 21 26 Maximum amount outstanding 265 441 290 317 Weighted average interest rate, computed on a daily basis 5.47 % 4.99 % 4.14 % 0.18 % Weighted average interest rate at end of period 5.47 5.47 4.64 N/A
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) 2023 2022 47.7 % 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)	[1],[2]
Credit Facilities	NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2023 (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 700 $ 180 $ 520 (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 Instrument Interest Rate Maturity Date 2023 2022 First mortgage bonds 2.60 % May 15, 2023 $ — $ 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds 2.25 April 1, 2031 425 425 First mortgage bonds 5.25 July 15, 2035 250 250 First mortgage bonds 6.25 June 1, 2036 400 400 First mortgage bonds 6.20 July 1, 2037 350 350 First mortgage bonds 5.35 Nov. 1, 2039 300 300 First mortgage bonds 4.85 Aug. 15, 2040 250 250 First mortgage bonds 3.40 Aug. 15, 2042 500 500 First mortgage bonds 4.125 May 15, 2044 300 300 First mortgage bonds 4.00 Aug. 15, 2045 300 300 First mortgage bonds 3.60 May 15, 2046 350 350 First mortgage bonds 3.60 Sept. 15, 2047 600 600 First mortgage bonds 2.90 March 1, 2050 600 600 First mortgage bonds 2.60 June 1, 2051 700 700 First mortgage bonds 3.20 April 1, 2052 425 425 First mortgage bonds (a) 4.50 June 1, 2052 500 500 First mortgage bonds (b) 5.10 May 15, 2053 800 — Other long-term debt 2 3 Unamortized discount (49) (45) Unamortized debt issuance cost (73) (66) Current maturities — (400) Total long-term debt $ 7,330 $ 6,542 (a) 2022 financing. (b)	[4],[5]
Schedule of Maturities of Long-term Debt	Maturities of long-term debt are as follows: (Millions of Dollars) 2024 $ — 2025 250 2026 — 2027 — 2028 150
Dividend Payment Restrictions	Requirements and actuals as of Dec. 31, 2023: Equity to Total Capitalization Ratio Equity to Total Capitalization Ratio Actual Low High 2023 47.2 % 57.6 % 52.3 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1,508 million $ 15,702 million $ 16,140 million
[1] All extension requests are subject to majority bank group approval. The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. Includes outstanding commercial paper and letters of credit. 2022 financing.

Revenues Revenues (Tables)

Revenues Revenues (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	NSP-Minnesota’s operating revenues consisted of the following: Year Ended Dec. 31, 2023 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,524 $ 368 $ 41 $ 1,933 C&I 2,298 309 — 2,607 Other 34 — 7 41 Total retail 3,856 677 48 4,581 Wholesale 354 — — 354 Transmission 263 — — 263 Interchange 493 — — 493 Other — 18 — 18 Total revenue from contracts with customers 4,966 695 48 5,709 Alternative revenue and other 275 59 — 334 Total revenues $ 5,241 $ 754 $ 48 $ 6,043 Year Ended Dec. 31, 2022 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,463 $ 510 $ 38 $ 2,011 C&I 2,376 433 — 2,809 Other 38 — 7 45 Total retail 3,877 943 45 4,865 Wholesale 668 — — 668 Transmission 287 — — 287 Interchange 514 — — 514 Other 15 19 — 34 Total revenue from contracts with customers 5,361 962 45 6,368 Alternative revenue and other 256 60 — 316 Total revenues $ 5,617 $ 1,022 $ 45 $ 6,684 Year Ended Dec. 31, 2021 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,374 $ 315 $ 33 $ 1,722 C&I 2,107 246 — 2,353 Other 33 — 6 39 Total retail 3,514 561 39 4,114 Wholesale 442 — — 442 Transmission 242 — — 242 Interchange 501 — — 501 Other 7 14 — 21 Total revenue from contracts with customers 4,706 575 39 5,320 Alternative revenue and other 388 48 — 436 Total revenues $ 5,094 $ 623 $ 39 $ 5,756

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
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 - 2016 March 2025 2020 September 2024
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs temporary: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Unrecognized tax benefit — Permanent tax positions $ 18 $ 31 Unrecognized tax benefit — Temporary tax positions — 3 Total unrecognized tax benefit $ 18 $ 34 Changes in unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Balance at Jan. 1 $ 34 $ 26 $ 24 Additions based on tax positions related to the current year 2 2 2 Additions for tax positions of prior years 1 6 — Reductions for tax positions of prior years (18) — — Reductions for tax positions related to settlements with taxing authorities (1) — — Balance at Dec. 31 $ 18 $ 34 $ 26
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, 2023 Dec. 31, 2022 NOL and tax credit carryforwards $ (18) $ (13)
Interest Payable related to Unrecognized Tax Benefits	Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (3) $ (2) $ (2) Interest benefit (expense) related to unrecognized tax benefits 4 (1) — Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31 $ 1 $ (3) $ (2)
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) 2023 2022 Federal NOL carryforward $ — $ 2 Federal tax credit carryforwards 777 909 Valuation Allowances for federal credit carryforwards (5) — State NOL carryforwards 1 184 Valuation allowances for state NOL carryforwards — (1) State tax credit carryforwards, net of federal detriment (a) 55 68 Valuation allowances for state credit carryforwards, net of federal benefit (b) (52) (58) (a) State tax credit carryforwards are net of federal detriment of $15 million and $18 million as of Dec. 31, 2023 and 2022, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $14 million and $15 million as of Dec. 31, 2023 and 2022, 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: 2023 2022 2021 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 7.0 7.0 7.0 Increases (decreases) in tax from: Wind PTCs (a) (39.5) (39.6) (27.8) Plant regulatory differences (b) (5.7) (6.7) (8.1) Other tax credits, net NOL & tax credit allowances (1.3) (1.3) (1.4) Other, net 0.3 (0.3) 0.7 Effective income tax rate (18.2) % (19.9) % (8.6) % (a) Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income. (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) 2023 2022 2021 Current federal tax (benefit) expense $ (154) $ 70 $ (10) Current state tax expense (benefit) 3 26 (1) Current change in unrecognized tax (benefit) expense (21) 8 1 Deferred federal tax expense (benefit) 5 (237) (87) Deferred state tax expense 51 23 49 Deferred change in unrecognized tax expense 8 — 2 Deferred ITCs (1) (2) (2) Total income tax benefit $ (109) $ (112) $ (48) Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2023 2022 2021 Deferred tax expense (benefit) excluding items below $ 326 $ (283) 109 Adjustments to deferred income taxes for wind production tax credit cash transfers (a) (150) — — Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (114) 70 (145) Tax benefit (expense) allocated to other comprehensive income and other 2 (1) — Deferred tax expense (benefit) $ 64 $ (214) $ (36) (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) 2023 2022 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,938 $ 2,708 Regulatory assets 190 188 Operating lease assets 129 98 Pension expense 64 68 Deferred fuel costs 20 49 Other 9 4 Total deferred tax liabilities $ 3,350 $ 3,115 Deferred tax assets: Tax credit carryforward $ 832 $ 977 Regulatory liabilities 323 324 Operating lease liabilities 129 98 Rate refund 59 28 NOL and tax credit valuation allowances (57) (58) Other employee benefits 31 27 Deferred ITCs 4 5 NOL carryforward — 15 Other 37 33 Total deferred tax assets $ 1,358 $ 1,449 Net deferred tax liability $ 1,992 $ 1,666 (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 income tax returns. As of Dec. 31, 2023, NSP-Minnesota’s earliest open tax years subject to examination by state taxing authorities under applicable statutes of limitations are as follows: State Tax Year(s) Expiration Minnesota 2014-2016 September 2025 Minnesota 2019 May 2024

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
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 — M ethods 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 $1.2 billion and $1 billion as of Dec. 31, 2023 and 2022, respectively, and unrealized losses were $29 million and $90 million as of Dec. 31, 2023 and 2022, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2023 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 41 $ 41 $ — $ — $ — $ 41 Commingled funds 721 — — — 1,049 1,049 Debt securities 784 — 771 9 — 780 Equity securities 508 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. Dec. 31, 2022 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds 803 — — — 1,178 1,178 Debt securities 738 — 669 6 — 675 Equity securities 406 999 1 — — 1,000 Total $ 1,976 $ 1,028 $ 670 $ 6 $ 1,178 $ 2,882 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments. For the years ended Dec. 31, 2023 and 2022, 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, 2023: Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ 4 $ 261 $ 269 $ 246 $ 780 Rabbi Trusts NSP-Minnesota has established a rabbi trust to provide partial funding for future distributions of its deferred compensation plan. The fair value of assets held in the rabbi trusts were $12 million and $12 million at Dec. 31, 2023 and 2022, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. 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, 2023, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2023, NSP-Minnesota had $150 million of unsettled interest rate derivatives. 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, see Note 11. 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. Derivative instruments 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 December 31, 2023 and 2022 for this purpose relate to FTR instruments administered by MISO. These instruments are intended to offset the impacts of transmission system congestion. Higher congestion costs in recent years have led to an increase in the fair value of FTRs. Settlements of FTRs are shared with electric customers through fuel and purchased energy cost-recovery mechanisms. 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, 2023, 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, 2023 Dec. 31, 2022 MWh of electricity 38 44 MMBtu of natural gas 64 88 (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’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. As of Dec. 31, 2023, four of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $24 million or 25% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Three of the ten most significant counterparties, comprising $26 million or 27% 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 $45 million or 47% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Five of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, 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, 2023 and 2022, there were $12 million and $4 million, respectively, of derivative liabilities with such underlying contract provisions, respectively. Also, certain contracts may 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, 2023 and 2022, there were approximately $80 million and $76 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. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2023 and 2022. 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 Loss Regulatory (Assets) and Liabilities 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) Natural gas commodity — — Total $ — $ (7) Year Ended Dec. 31, 2021 Other derivative instruments Electric commodity $ — $ 3 Natural gas commodity — (3) Total $ — $ — 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 Loss Regulatory 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 Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 2 (a) $ — $ — Total $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 51 (b) Electric commodity $ — $ (3) (c) $ — Natural gas commodity — 1 (d) (6) (d)(e) Total $ — $ (2) $ 45 (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, 2023, 2022 and 2021. Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2023 Dec. 31, 2022 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 7 $ 32 $ 32 $ 71 $ (42) $ 29 $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 Electric commodity — — 23 23 (7) 16 — — 58 58 (2) 56 Natural gas commodity — 5 — 5 — 5 — 5 — 5 — 5 Total current derivative assets $ 7 $ 37 $ 55 $ 99 $ (49) $ 50 $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 7 $ 43 $ 45 $ 95 $ (34) $ 61 $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 Total noncurrent derivative assets $ 7 $ 43 $ 45 $ 95 $ (34) $ 61 $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 Dec. 31, 2023 Dec. 31, 2022 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Interest rate $ — $ 7 $ — $ 7 $ — $ 7 $ — $ — $ — $ — $ — $ — Other derivative instruments: Commodity trading 6 60 5 71 (43) 28 23 60 6 89 (63) 26 Electric commodity — — 7 7 (7) — — — 2 2 (2) — Natural gas commodity — 3 — 3 — 3 — 2 — 2 — 2 Total current derivative liabilities $ 6 $ 70 $ 12 $ 88 $ (50) 38 $ 23 $ 62 $ 8 $ 93 $ (65) 28 PPAs (b) 6 14 Current derivative instruments $ 44 $ 42 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 14 $ 49 $ 37 $ 100 $ (36) $ 64 $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 Total noncurrent derivative liabilities $ 14 $ 49 $ 37 $ 100 $ (36) 64 $ 37 $ 55 $ 42 $ 134 $ (60) 74 PPAs (b) 22 28 Noncurrent derivative instruments $ 86 $ 102 (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, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $3 million and $6 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) 2023 2022 2021 Balance at Jan. 1 $ 107 $ 56 $ (11) Purchases (a) 98 157 54 Settlements (a) (65) (195) (82) Net transactions recorded during the period: Gains recognized in earnings (b) 15 91 72 Net (losses) gains recognized as regulatory assets and liabilities (a) (104) (2) 23 Balance at Dec. 31 $ 51 $ 107 $ 56 (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 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: 2023 2022 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 7,330 $ 6,561 $ 6,942 $ 5,995 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, 2023 and 2022, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
Cost and Fair Value of Nuclear Decommissioning Fund Investments	Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2023 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 41 $ 41 $ — $ — $ — $ 41 Commingled funds 721 — — — 1,049 1,049 Debt securities 784 — 771 9 — 780 Equity securities 508 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. Dec. 31, 2022 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds 803 — — — 1,178 1,178 Debt securities 738 — 669 6 — 675 Equity securities 406 999 1 — — 1,000 Total $ 1,976 $ 1,028 $ 670 $ 6 $ 1,178 $ 2,882 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and 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, 2023: Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ 4 $ 261 $ 269 $ 246 $ 780
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, 2023 Dec. 31, 2022 MWh of electricity 38 44 MMBtu of natural gas 64 88 (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 Loss Regulatory (Assets) and Liabilities 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) Natural gas commodity — — Total $ — $ (7) Year Ended Dec. 31, 2021 Other derivative instruments Electric commodity $ — $ 3 Natural gas commodity — (3) Total $ — $ — 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 Loss Regulatory 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 Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 2 (a) $ — $ — Total $ 2 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 51 (b) Electric commodity $ — $ (3) (c) $ — Natural gas commodity — 1 (d) (6) (d)(e) Total $ — $ (2) $ 45 (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.
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, 2023 Dec. 31, 2022 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 7 $ 32 $ 32 $ 71 $ (42) $ 29 $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 Electric commodity — — 23 23 (7) 16 — — 58 58 (2) 56 Natural gas commodity — 5 — 5 — 5 — 5 — 5 — 5 Total current derivative assets $ 7 $ 37 $ 55 $ 99 $ (49) $ 50 $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 7 $ 43 $ 45 $ 95 $ (34) $ 61 $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 Total noncurrent derivative assets $ 7 $ 43 $ 45 $ 95 $ (34) $ 61 $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 Dec. 31, 2023 Dec. 31, 2022 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative liabilities Derivatives designated as cash flow hedges: Interest rate $ — $ 7 $ — $ 7 $ — $ 7 $ — $ — $ — $ — $ — $ — Other derivative instruments: Commodity trading 6 60 5 71 (43) 28 23 60 6 89 (63) 26 Electric commodity — — 7 7 (7) — — — 2 2 (2) — Natural gas commodity — 3 — 3 — 3 — 2 — 2 — 2 Total current derivative liabilities $ 6 $ 70 $ 12 $ 88 $ (50) 38 $ 23 $ 62 $ 8 $ 93 $ (65) 28 PPAs (b) 6 14 Current derivative instruments $ 44 $ 42 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 14 $ 49 $ 37 $ 100 $ (36) $ 64 $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 Total noncurrent derivative liabilities $ 14 $ 49 $ 37 $ 100 $ (36) 64 $ 37 $ 55 $ 42 $ 134 $ (60) 74 PPAs (b) 22 28 Noncurrent derivative instruments $ 86 $ 102 (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, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $3 million and $6 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)
Changes in Level 3 Commodity Derivatives	Changes in Level 3 commodity derivatives: Year Ended Dec. 31 (Millions of Dollars) 2023 2022 2021 Balance at Jan. 1 $ 107 $ 56 $ (11) Purchases (a) 98 157 54 Settlements (a) (65) (195) (82) Net transactions recorded during the period: Gains recognized in earnings (b) 15 91 72 Net (losses) gains recognized as regulatory assets and liabilities (a) (104) (2) 23 Balance at Dec. 31 $ 51 $ 107 $ 56 (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 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	2023 2022 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 7,330 $ 6,561 $ 6,942 $ 5,995

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2023
Benefit Plans and Other Postretirement Benefits [Abstract]
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 321 $ 309 $ 15 $ 16 Prior service credit — — — (1) Total $ 321 $ 309 $ 15 $ 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 $ 11 $ 12 $ — Noncurrent regulatory assets 310 297 14 14 Deferred income taxes — — Net-of-tax accumulated other comprehensive income — 1 1 Total $ 321 $ 309 $ 15 $ 15 Measurement date Dec 31, 2023 Dec 31, 2022 Dec 31, 2023 Dec 31, 2022
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	Projected Benefit Payments NSP-Minnesota’s projected benefit payments: (Millions of Dollars) Projected Net Projected Postretirement Health Care Benefit Payments (a) 2024 $ 100 $ 5 2025 $ 56 $ 5 2026 $ 56 $ 4 2027 $ 56 $ 4 2028 $ 55 $ 4 2029-2033 $ 273 $ 15 (a) Amount is reported net of expected Medicare Part D subsidies, which are immaterial.
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 Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Change in Benefit Obligation: Obligation at Jan. 1 $ 657 $ 877 $ 48 $ 64 Service cost 21 27 — — Interest cost 36 25 3 2 Plan amendments (1) 1 — — Actuarial (gain) loss 30 (139) (2) (13) Benefit payments (83) (134) (7) (5) Obligation at Dec. 31 $ 660 $ 657 $ 42 $ 48 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 570 $ 853 $ 5 $ 3 Actual return on plan assets 52 (154) — — Employer contributions 23 5 5 7 Benefit payments (83) (134) (7) (5) Fair value of plan assets at Dec. 31 $ 562 $ 570 $ 3 $ 5 Funded status of plans at Dec. 31 $ (98) $ (87) $ (39) $ (43) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (2) $ (1) Noncurrent liabilities (98) (87) (37) (42) Net amounts recognized $ (98) $ (87) $ (39) $ (43) Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2023 2022 2023 2022 Discount rate for year-end valuation 5.49 % 5.80 % 5.54 % 5.80 % Expected average long-term increase in compensation level 4.25 % 4.25 % N/A N/A Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012 Health care costs trend rate — initial: Pre-65 N/A N/A 6.50 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.50 % 5.50 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.50 % 4.50 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.50 % 4.50 % Years until ultimate trend is reached N/A N/A 6 7
Components of Net Periodic Benefit Costs	Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2021 2023 2022 2021 Service cost $ 21 $ 27 $ 30 $ — $ — $ — Interest cost 36 25 25 3 2 2 Expected return on plan assets (46) (48) (52) — — — Amortization of prior service cost — — — (1) (3) (3) Amortization of net loss 11 24 34 — 1 2 Settlement charge (a) — 38 35 — — — Net periodic pension cost 22 66 72 2 — 1 Effects of regulation 16 (32) (44) — — — Net benefit cost recognized for financial reporting $ 38 $ 34 $ 28 $ 2 $ — $ 1 Significant Assumptions Used to Measure Costs: Discount rate 5.80 % 3.08 % 2.71 % 5.80 % 3.09 % 2.65 % Expected average long-term increase in compensation level 4.25 3.75 3.75 — — — Expected average long-term rate of return on assets 7.25 6.60 6.60 5.00 4.10 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 2022 and 2021, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $38 million and $35 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, 2023 (a) Dec. 31, 2022 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 46 $ — $ — $ — $ 46 $ 26 $ — $ — $ — $ 26 Commingled funds 110 — — 265 375 201 — — 201 402 Debt securities — 127 1 — 128 — 129 1 — 130 Equity securities 8 — — — 8 11 — — — 11 Other — 5 — — 5 — 1 — — 1 Total $ 164 $ 132 $ 1 $ 265 $ 562 $ 238 $ 130 $ 1 $ 201 $ 570 (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, 2023 (a) Dec. 31, 2022 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Insurance contracts — — — — — — 1 — — 1 Commingled funds $ — $ — $ — $ 1 $ 1 $ 1 $ — $ — $ 1 $ 2 Debt securities — 2 — — 2 — 2 — — 2 Total $ — $ 2 $ — $ 1 $ 3 $ 1 $ 3 $ — $ 1 $ 5 (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 2023. No assets were transferred in or out of Level 3 for 2022.
Postretirement Benefits Plan
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	Targeted asset allocations: Pension Benefits Postretirement Benefits 2023 2022 2023 2022 Long-duration fixed income and interest rate swap securities 38 % 38 % — % — % Domestic and international equity securities 31 33 9 16 Alternative investments 20 18 13 12 Short-to-intermediate fixed income securities 9 9 77 71 Cash 2 2 1 1 Total 100 % 100 % 100 % 100 % The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Asset Retirement Obligations	NSP-Minnesota’s AROs were as follows: 2023 (Millions Jan. 1, 2023 Amounts Incurred (a) Amounts Accretion Cash Flow Revisions (b) Dec. 31, 2023 Electric Nuclear $ 2,160 $ — $ — $ 105 $ (158) $ 2,107 Wind 416 10 — 15 (17) 424 Steam and other production 75 — (1) 3 — 77 Distribution 16 — — 1 — 17 Natural gas Transmission and distribution 59 — — 2 (29) 32 Other Miscellaneous 1 — — — — 1 Total liability $ 2,727 $ 10 $ (1) $ 126 $ (204) $ 2,658 (a) Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. (b) In 2023, AROs were revised for changes in timing and estimates of cash flows. 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. 2022 (Millions Jan. 1, 2022 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2022 Electric Nuclear $ 2,056 $ — $ 104 $ — $ 2,160 Wind 384 25 15 (8) 416 Steam and other production 73 — 2 — 75 Distribution 16 — — — 16 Natural gas Transmission and distribution 55 — 2 2 59 Other Miscellaneous 1 — — — 1 Total liability $ 2,585 $ 25 $ 123 $ (6) $ 2,727 (a) Amounts incurred relate to the wind farms placed in service in 2022 (Dakota Range and Rock Aetna). (b) In 2022, AROs were revised for changes in timing and estimates of cash flows. Changes in electric wind AROs were related to the repowering and extended retirement date of Nobles. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
Assets and Liabilities, Lessee [Table Text Block]	Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 PPAs $ 709 $ 556 Other 125 78 Gross operating lease ROU assets 834 634 Accumulated amortization (395) (310) Net operating lease ROU assets $ 439 $ 324
Lease, Cost [Table Text Block]	Components of lease expense: (Millions of Dollars) 2023 2022 2021 Operating leases PPA capacity payments $ 100 $ 98 $ 96 Other operating leases (a) 13 9 8 Total operating lease expense (b) $ 113 $ 107 $ 104 (a) Includes short-term lease expense o f $2 million, $3 million and $2 million for 2023, 2022 and 2021, respectively. (b)
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Commitments under operating leases as of Dec. 31, 2023: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2024 $ 99 $ 11 $ 110 2025 101 11 112 2026 89 11 100 2027 72 11 83 2028 40 10 50 Thereafter — 125 125 Total minimum obligation 401 179 580 Interest component of obligation (37) (80) (117) Present value of minimum obligation $ 364 $ 99 463 Less current portion (91) Noncurrent operating lease liabilities $ 372 Weighted-average remaining lease term in years 9.8 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2039.
Estimated Minimum Purchases Under Fuel Contracts	Estimated minimum purchases for these contracts as of Dec. 31, 2023: (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2024 $ 115 $ 142 $ 88 $ 148 2025 62 179 1 131 2026 21 63 — 128 2027 1 180 — 96 2028 — 50 — 28 Thereafter — 177 — 47 Total (a) $ 199 $ 791 $ 89 $ 578 (a) Includes amounts allocated to NSP-Wisconsin through intercompany charges.
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements	At Dec. 31, 2023, 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) 2024 $ 63 $ 174 2025 27 53 2026 9 10 2027 8 10 2028 1 10 Thereafter 2 18 Total (b) $ 110 $ 275 (a) Excludes contingent energy payments for renewable energy PPAs. (b) Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2023
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: 2023 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total 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) 2022 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (17) $ (3) $ (20) Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 1 (a) — 1 Net current period other comprehensive income 1 1 2 Accumulated other comprehensive loss at Dec. 31 $ (16) $ (2) $ (18) (a) Included in interest charges.

Segments and Related Informat_2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	NSP-Minnesota’s segment information: (Millions of Dollars) 2023 2022 2021 Regulated Electric Operating revenues — external (a) $ 5,241 $ 5,617 $ 5,094 Intersegment revenue 1 1 1 Total revenues $ 5,242 $ 5,618 $ 5,095 Depreciation and amortization 909 953 869 Interest charges and financing costs 278 257 240 Income tax benefit (127) (127) (53) Net income 648 626 566 Regulated Natural Gas Operating revenues — external (b) $ 754 $ 1,022 $ 623 Intersegment revenue 2 2 1 Total revenues $ 756 $ 1,024 $ 624 Depreciation and amortization 71 60 56 Interest charges and financing costs 26 22 18 Income tax expense 10 14 6 Net income 38 45 29 All Other Total revenues $ 48 $ 45 $ 39 Depreciation and amortization 1 1 1 Income tax (benefit) expense 8 1 (1) Net income 21 4 11 Consolidated Total Total revenues (a)(b) $ 6,046 $ 6,687 $ 5,758 Reconciling eliminations (3) (3) (2) Total operating revenues $ 6,043 $ 6,684 $ 5,756 Depreciation and amortization 981 1,014 926 Interest charges and financing costs 304 279 258 Income tax benefit (109) (112) (48) Net income 707 675 606 (a) Operating revenues include $493 million, $514 million and $501 million of affiliate electric revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information. (b)

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2023
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) 2023 2022 2021 Operating revenues: Electric $ 493 $ 514 $ 501 Gas 1 — 1 Operating expenses: Purchased power 63 70 67 Transmission expense 142 132 121 Other operating expenses — paid to Xcel Energy Services Inc. 719 673 615 Interest income 1 1 — Interest expense 5 1 — Accounts receivable and payable with affiliates at Dec. 31: 2023 2022 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 9 $ — $ 4 $ — PSCo 5 — — 2 SPS — 4 — 3 Other subsidiaries of Xcel Energy Inc. 1 85 41 84 $ 15 $ 89 $ 45 $ 89

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.70%	4%	3.70%
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract]
Allowance for bad debts	$ 48	$ 46
Alternative Revenue Programs [Abstract]
maximum number of months following annual period	24 months
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 356	384
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	$ 219	200
Public Utilities, Inventory, Fuel
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	105	103
Public Utilities, Inventory, Natural Gas
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 32	$ 81

Property Plant and Equipment (D

Property Plant and Equipment (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 26,452	$ 24,923
Accumulated depreciation and amortization		8,044	7,734
Property, Plant and Equipment, Net		18,757	17,478
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		21,206	20,114
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,256	2,100
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,301	1,156
Plant to be Retired [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	604	646
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,085	907
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment		3,337	3,183
Accumulated depreciation and amortization		$ 2,988	$ 2,894
[1]Sherco 2 retired in December 2023. Amounts include Sherco 1 and 3 and A.S. King for 2023 and Sherco Units 1, 2 and 3 and A.S. King for 2022. Balance is presented net of accumulated depreciation.

Property Plant and Equipment _2

Property Plant and Equipment Property Plant and Equipment Joint Ownership (Details) $ in Millions	Dec. 31, 2023 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,703	[1]
Accumulated Depreciation	752	[1]
CWIP	2
Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	633
Accumulated Depreciation	$ 480
Percent Owned	59%
Electric Generation | Sherco Common Facilities Units 1, 2 and 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 185
Accumulated Depreciation	$ 121
Percent Owned	80%
Electric Generation | Sherco Substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 5
Accumulated Depreciation	$ 4
Percent Owned	59%
Electric Transmission | Grand Meadow
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 11
Accumulated Depreciation	$ 4
Percent Owned	50%
Electric Transmission | Huntley Wilmarth
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 49
Accumulated Depreciation	$ 2
Percent Owned	50%
Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 820
Accumulated Depreciation	$ 141
Percent Owned	51%
[1] Projects additionally include $2 million in CWIP.

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 250	$ 384
Regulatory assets		837	894
Regulatory assets not currently earning a return		479	369
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		18	12	[1]
Regulatory assets		340	347	[1]
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0	[1]
Regulatory assets		127	112	[1]
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		8	10	[1]
Regulatory assets		96	103	[1]
Deferred Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		16	110	[1]
Regulatory assets		$ 58	65	[1]
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		3 years
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 4	4	[1]
Regulatory assets		$ 38	42	[1]
Regulatory Asset, Amortization Period		11 years
Benson purchase power agreement termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 10	10	[1]
Regulatory assets		$ 36	45	[1]
Regulatory Asset, Amortization Period		5 years
MISO capacity revenue tracker
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 36	0	[1]
Regulatory assets		$ 26	0	[1]
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	[2]	$ 9	16	[1]
Regulatory assets	[2]	22	28	[1]
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		1	7	[1]
Regulatory assets		20	19	[1]
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	6	6	[1]
Regulatory assets	[3]	$ 19	19	[1]
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		$ 43	30	[1]
Regulatory assets		$ 19	12	[1]
Nuclear Refueling Outage Costs | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Nuclear Refueling Outage Costs | Maximum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		2 years
Loss on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 1	1	[1]
Regulatory assets		9	10	[1]
Sales True-Up and Revenue Decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		7	53	[1]
Regulatory assets		2	0	[1]
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		38	50	[1]
Regulatory assets		0	0	[1]
Gas Pipeline Inspection and Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		37	42	[1]
Regulatory assets		0	0	[1]
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[4]	0	0	[1]
Regulatory assets	[4]	0	62	[1]
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		16	33	[1]
Regulatory assets		$ 25	$ 30	[1]
[1] Prior period amounts have been reclassified to conform with current year presentation. Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 300	$ 191
Regulatory Liability, Noncurrent	[1]	$ 2,097	1,983
Minimum [Member] | Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory Asset, Amortization Period		1 year
Deferred income tax adjustments and TCJA refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	$ 5	6
Regulatory Liability, Noncurrent	[2]	1,157	1,200
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		741	693
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	0	0
Regulatory Liability, Noncurrent	[3]	90	0
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		9	6
Regulatory Liability, Noncurrent		27	19
Revenue Decoupling
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		18	0
Regulatory Liability, Noncurrent		13	22
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		13	17
Formula Rates
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		8	6
Regulatory Liability, Noncurrent		$ 9	9
Formula Rates | Minimum [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Formula Rates | Maximum [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	$ 16	56
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		$ 27	42
Regulatory Liability, Noncurrent		$ 0	0
Conservation Programs | Minimum [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 15	0
Regulatory Liability, Noncurrent		0	0
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		143	26
Regulatory Liability, Noncurrent		0	0
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		59	49
Regulatory Liability, Noncurrent		47	23
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 187	$ 67
[1] Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

Short-Term Debt (Details)

Short-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Short-term Debt [Line Items]
Short-term Debt	$ 165	$ 165	$ 207
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	21	17	0	6
Short-term Debt, Maximum Amount Outstanding During Period	$ 113	$ 135	$ 4	$ 236
Line of Credit Facility, Interest Rate During Period	5.34%	4.97%	3.87%	0.07%
Commercial Paper [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 700	$ 700	$ 700	$ 500
Short-term Debt	165	165	207	0
Short-term Debt, Average Outstanding Amount	112	92	21	26
Short-term Debt, Maximum Amount Outstanding During Period	$ 265	$ 441	$ 290	$ 317
Short-term Debt, Weighted Average Interest Rate, at Point in Time	5.47%	5.47%	4.64%
Line of Credit Facility, Interest Rate During Period	5.47%	4.99%	4.14%	0.18%

Letters of Credit (Details)

Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Line of Credit Facility [Line Items]
Short-term Debt	$ 165	$ 207
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Short-term Debt	$ 15
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	$ 65

Credit Facilities (Details)

Credit Facilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Line of Credit Facility [Line Items]
Short-term Debt		$ 165	$ 207
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Short-term Debt		15
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		$ 65
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[1]	47.70%	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%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15%
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]	180
Line of Credit Facility, Remaining Borrowing Capacity		520
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%. All extension requests are subject to majority bank group approval. This credit facility matures in September 2027. Includes outstanding commercial paper and letters of credit.

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (49)	$ (45)
Unamortized debt expense		(73)	(66)
Long-term Debt, Current Maturities		0	400
Long-term Debt		7,330	6,542
2024		0
2025		250
2026		0
2027		0
2028		150
First Mortgage Bonds | Series Due May 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	400
Debt Instrument, Interest Rate, Stated Percentage		2.60%
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%
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		$ 700	700
Debt Instrument, Interest Rate, Stated Percentage		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	[1]	$ 500	500
Debt Instrument, Interest Rate, Stated Percentage	[1]	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	0
Debt Instrument, Interest Rate, Stated Percentage	[2]	5.10%
Long-term Debt
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 2	$ 3
Letter of Credit [Member]
Long-Term Borrowings and Other Financing Instruments
Line of Credit Facility, Expiration Period		1 year
[1] 2022 financing.

Deferred Financing Costs (Detai

Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 73	$ 66

Dividend and Other Capital-Rela

Dividend and Other Capital-Related Restrictions (Details) $ in Millions	Dec. 31, 2023 USD ($)
Dividend and Other Capital-Related Restrictions [Abstract]
Equity to total capitalization ratio, low end of range (in hundredths)	47.20%
Equity to total capitalization ratio, high end of range (in hundredths)	57.60%
Equity to total capitalization ratio	52.30%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1,508
Capitalization, Short term debt, long term debt and equity	15,702
Maximum total capitalization	$ 16,140

Revenues Revenues (Details)

Revenues Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 5,709	$ 6,368	$ 5,320
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,581	4,865	4,114
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,933	2,011	1,722
Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,607	2,809	2,353
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	41	45	39
Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	354	668	442
Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	263	287	242
Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	493	514	501
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	18	34	21
Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	334	316	436
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,966	5,361	4,706
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,856	3,877	3,514
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,524	1,463	1,374
Regulated Electric | Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,298	2,376	2,107
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	34	38	33
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	354	668	442
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	263	287	242
Regulated Electric | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	493	514	501
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	15	7
Regulated Electric | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	275	256	388
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	695	962	575
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	677	943	561
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	368	510	315
Regulated Natural Gas | Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	309	433	246
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	0	0	0
Regulated Natural Gas | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	18	19	14
Regulated Natural Gas | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	59	60	48
All Other | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	48	45	39
All Other | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	48	45	39
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	41	38	33
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	7	7	6
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 | Other
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	6,043	6,684	5,756
Total revenues | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	5,241	5,617	5,094
Total revenues | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	754	1,022	623
Total revenues | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 48	$ 45	$ 39

Unrecognized Tax Benefits

Unrecognized Tax Benefits - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 18,000,000	$ 31,000,000
Unrecognized tax benefit — Temporary tax positions	0	3,000,000
Total unrecognized tax benefit	18,000,000	34,000,000	$ 26,000,000	$ 24,000,000
Additions based on tax positions related to the current year	2,000,000	2,000,000	2,000,000
Additions for tax positions of prior years	1,000,000	6,000,000	0
Reductions for tax positions of prior years	(18,000,000)	0	0
NOL and tax credit carryforwards	(18,000,000)	(13,000,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible	5,000,000
Unrecognized Tax Benefits, Income Tax Penalties Expense	0	0
Payable for interest related to unrecognized tax benefits at Jan. 1	1,000,000	(3,000,000)	(2,000,000)	$ (2,000,000)
Interest benefit (expense) related to unrecognized tax benefits	$ 4,000,000	$ (1,000,000)	$ 0

Other Income Tax Matters

Other Income Tax Matters - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Income Tax [Line Items]
Federal NOL carryforward		$ 0	$ 2
Tax Credit Carryforward, Amount		777	909
State NOL carryforwards		1	184
Valuation allowances for state NOL carryforwards		0	(1)
state tax credit carryforward, net of federal detirment	[1]	55	68
valuation allowances for state credit carryforwards, net of federal benefit	[2]	$ (52)	$ (58)
Federal statutory rate		21%	21%		21%
State income tax on pretax income, net of federal tax effect		7%	7%		7%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	[3]	(39.50%)	(39.60%)		(27.80%)
Plant regulatory differences (b)	[4]	(5.70%)	(6.70%)		(8.10%)
Other tax credits, net NOL & tax credit allowances		(1.30%)	(1.30%)		(1.40%)
Other, net		0.30%	(0.30%)		0.70%
Effective income tax rate		(18.20%)	(19.90%)		(8.60%)
Income tax benefit		$ (109)	$ (112)		$ (48)
Deferred tax expense (benefit) excluding items below		326	(283)		109
Adjustments to deferred income taxes for wind production tax credit cash transfers	[5]	(150)	0		0
Adjustments to deferred income taxes for wind production tax credit cash transfers (a)		(114)	70		(145)
Tax benefit (expense) allocated to other comprehensive income and other		2	(1)		0
Deferred tax expense (benefit)		64	214		36
Operating Lease, Liability		463
Tax Credit Carryforward, Valuation Allowance		(5)	0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		1	0		0
income tax expense [Member]
Income Tax [Line Items]
Current federal tax (benefit) expense		(154)	70		(10)
Current state tax expense (benefit)		3	26		(1)
Current change in unrecognized tax (benefit) expense		(21)	8		1
Deferred federal tax expense (benefit)		5	(237)		(87)
Deferred state tax expense		51	23		49
Deferred change in unrecognized tax expense		8	0		2
Deferred ITCs		(1)	(2)		(2)
Income tax benefit		(109)	(112)		$ (48)
Net Deferred Tax Liablility [Member]
Income Tax [Line Items]
Tax Credit Carryforward, Amount		832	977	[6]
Deferred ITCs		4	5	[6]
Deferred tax expense (benefit)		1,358	1,449	[6]
Differences between book and tax bases of property		2,938	2,708	[6]
Regulatory assets		190	188	[6]
Operating lease assets		129	98	[6]
Deferred fuel costs		20	49	[6]
Deferred tax liability - Pension expense		64	68	[6]
Other		9	4	[6]
Total deferred tax liabilities		3,350	3,115	[6]
Regulatory liabilities		323	324	[6]
Operating Lease, Liability		129	98	[6]
Tax Credit Carryforward, Valuation Allowance		(57)	(58)	[6]
other employee benefits		31	27	[6]
Operating Loss Carryforwards		0	15
Other		37	33	[6]
Net deferred tax liability		1,992	1,666	[6]
Deferred Tax Assets Rate Refund		59	28	[6]
State and Local Jurisdiction
Income Tax [Line Items]
Federal detriment		15	18
Federal Benefit		$ 14	$ 15
[1] State tax credit carryforwards are net of federal detriment of $15 million and $18 million as of Dec. 31, 2023 and 2022, respectively. Valuation allowances for state tax credit carryforwards were net of federal benefit of $14 million and $15 million as of Dec. 31, 2023 and 2022, respectively. Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income. 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. Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

Nuclear Decommissioning Fund (D

Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022
Investments [Abstract]
Miscellaneous investments	$ 51		$ 48
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	4
Due in 1 to 5 Years	261
Due in 5 to 10 Years	269
Due after 10 Years	246
Total	780
Fair Value Measured on a Recurring Basis | Cost
Investments [Abstract]
Decommissioning Fund Investments	2,054	[1]	1,976	[2]
Fair Value Measured on a Recurring Basis | Cost | Cash equivalents
Investments [Abstract]
Cash equivalents	41	[1]	29	[2]
Fair Value Measured on a Recurring Basis | Cost | Commingled Funds
Investments [Abstract]
Investments, Fair Value Disclosure	721	[1]	803	[2]
Fair Value Measured on a Recurring Basis | Cost | Debt Securities [Member]
Investments [Abstract]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	784	[1]	738	[2]
Fair Value Measured on a Recurring Basis | Cost | Equity Securities
Investments [Abstract]
Equity Securities, FV-NI, Current	508	[1]	406	[2]
Fair Value Measured on a Recurring Basis | Fair Value
Investments [Abstract]
Alternative Investment	1,049	[1]	1,178	[2]
Decommissioning Fund Investments	3,211	[1]	2,882	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents
Investments [Abstract]
Cash equivalents	41	[1]	29	[2]
Alternative Investment	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds
Investments [Abstract]
Alternative Investment	1,049	[1]	1,178	[2]
Investments, Fair Value Disclosure	1,049	[1]	1,178	[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	780	[1]	675	[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	1,341	[1]	1,000	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Investments [Abstract]
Decommissioning Fund Investments	1,380	[1]	1,028	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash equivalents
Investments [Abstract]
Cash equivalents	41	[1]	29	[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	1,339	[1]	999	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Investments [Abstract]
Decommissioning Fund Investments	773	[1]	670	[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	771	[1]	669	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Equity Securities
Investments [Abstract]
Equity Securities, FV-NI, Current	2	[1]	1	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Investments [Abstract]
Decommissioning Fund Investments	9	[1]	6	[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	9	[1]	6	[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	$ 3,200		$ 2,900
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments.

Rabbi Trust (Details)

Rabbi Trust (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Unrealized Gain	$ 1,200		$ 1,000
Debt Securities, Available-for-Sale, Unrealized Loss	29		90
Fair Value Measured on a Recurring Basis | Cost | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	41	[1]	29	[2]
Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	12		12
Fair Value Measured on a Recurring Basis | Fair Value | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	41	[1]	29	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	41	[1]	29	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	$ 0	[1]	$ 0	[2]
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments.

Interest Rate Derivatives (Deta

Interest Rate Derivatives (Details) - Interest Rate Swap [Member] $ in Millions	Dec. 31, 2023 USD ($)
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	$ 1
Derivative Liability, Notional Amount	$ 150

Commodity Derivatives (Details)

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2023 USD ($) MWh MMBTU	Dec. 31, 2022 MWh MMBTU
Electric Commodity
Derivative [Line Items]
Notional amount | MWh	[1],[2]	38	44
Natural Gas Commodity
Derivative [Line Items]
Notional amount | MMBTU	[1],[2]	64	88
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. Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

Consideration of Credit Risk an

Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk $ in Millions	Dec. 31, 2023 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	5
External Credit Rating, Investment Grade
Derivative [Line Items]
Number of most significant counterparties	4
Credit exposure for the most significant counterparties | $	$ 24
Percentage of credit exposure for the most significant counterparties	25%
Internal Investment Grade [Member]
Derivative [Line Items]
Number of most significant counterparties	3
Credit exposure for the most significant counterparties | $	$ 26
Percentage of credit exposure for the most significant counterparties	27%
External Credit Rating, Non Investment Grade
Derivative [Line Items]
Number of most significant counterparties	3
Credit exposure for the most significant counterparties | $	$ 45
Percentage of credit exposure for the most significant counterparties	47%

Qualifying Cash Flow Hedges (De

Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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		49	7	0
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)		45	(3)	2
Derivative, Gain (Loss) on Derivative, Net		(10)	9	45
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		48	7	(3)
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]	45	(1)	3
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	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		1	0	3
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)	[2]	0	(2)	1
Derivative, Gain (Loss) on Derivative, Net	[2],[3]	(8)	(8)	(6)
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]	(2)	17	51
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		3
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		1	1	2
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		3
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[5]	1	1	2
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. 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. Relates primarily to option premium amortization. Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. Recorded to interest charges.

Credit Related Contingent Featu

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 12	$ 4
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	80	76
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

Recurring Fair Value Measuremen

Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Assets	Assets
Derivative Liability, Current		$ 44	$ 42
Derivative Liability, Net		$ 86	$ 102
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Liabilities, Other than Long-Term Debt, Noncurrent	Liabilities, Other than Long-Term Debt, Noncurrent
Return Cash Collateral		$ 0	$ 0
Reclaim Cash Collateral		$ 3	$ 6
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Assets, Current	Assets, Current
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]			Liabilities, Current
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 107	$ 56	$ (11)
Purchases	[1]	98	157	54
Settlements	[1]	(65)	(195)	(82)
Gains (losses) recognized in earnings	[2]	15	91	72
Net gains (losses) recognized as regulatory assets and liabilities	[1]	(104)	(2)	23
Balance at end of period		51	107	$ 56
Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		50	89
Derivative Asset, Net		61	68
Derivative Liability, Current		38	28
Derivative Liability, Net		64	74
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		29	28
Derivative Asset, Net		61	68
Derivative Liability, Current		28	26
Derivative Liability, Net		64	74
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		23	58
Netting	[3]	(7)	(2)
Derivative Asset, Current		16	56
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	58
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		5	5
Netting	[3]	0	0
Derivative Asset, Current		5	5
Derivative Liability, Current		3	2
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		5	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		7	0
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		99	149
Netting	[3]	(49)	(60)
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		7	15
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		37	43
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		55	91
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		71	86
Netting	[3]	(42)	(58)
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		7	15
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		32	38
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		32	33
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		95	127
Netting	[3]	(34)	(59)
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		7	21
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		43	40
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		45	66
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		95	127
Netting	[3]	(34)	(59)
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		7	21
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		43	40
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		45	66
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		88	93
Netting	[3]	(50)	(65)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		6	23
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		70	62
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		12	8
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		71	89
Netting	[3]	(43)	(63)
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	23
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		60	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	6
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		7	2
Netting	[3]	(7)	(2)
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		7	2
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		3	2
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		3	2
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		7	0
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		7	0
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		100	134
Netting	[3]	(36)	(60)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		14	37
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		49	55
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		37	42
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		100	134
Netting	[3]	(36)	(60)
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		14	37
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		49	55
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		37	42
Fair Value, Measurements, Nonrecurring | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Current	[4]	6	14
Derivative Liability, Net	[4]	$ 22	$ 28
[1] Relates primarily to FTR instruments administered by MISO. Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses. 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, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $3 million and $6 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. 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.

Fair Value of Long-Term Debt (D

Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term Debt, Gross	$ 7,330	$ 6,942
Long-term debt, Fair Value	$ 6,561	$ 5,995

Benefit Plans and Other Postr_3

Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
annual interest crediting rates	$ 4.67	$ 4.86	$ 1.96
Total benefit obligation		$ 2,000,000
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total benefit obligation	$ 2,000,000

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Pension Benefits [Abstract]
Total benefit obligation					$ 2
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			$ 2
Pension Plan
Pension Benefits [Abstract]
Fair value of plan assets			562	[1]	570	[1]	$ 853
Total benefit obligation			660		657		877
Net benefit cost recognized for financial reporting			$ 38		$ 34		$ 28
Expected average long-term rate of return on assets (as a percent)			7.25%		6.60%		6.60%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100%		100%
Pension Plan | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			38%		38%
Pension Plan | Domestic and international equity securities
Pension Benefits [Abstract]
Fair value of plan assets	[1]		$ 8		$ 11
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			31%		33%
Pension Plan | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			9%		9%
Pension Plan | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			20%		18%
Pension Plan | Cash
Pension Benefits [Abstract]
Fair value of plan assets	[1]		$ 46		$ 26
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			2%		2%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			$ 12		$ 11
Net benefit cost recognized for financial reporting			$ 2		$ 17
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.

Benefit Plans and Other Postr_5

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - USD ($) $ in Millions		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
assets transferred		$ 0		$ 0
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		562	[1]	570	[1]	$ 853
Pension Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	164		238
Pension Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	132		130
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]	265		201
Pension Plan | Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	46		26
Pension Plan | Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	46		26
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]	375		402
Pension Plan | Commingled Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	110		201
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]	265		201
Pension Plan | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	128		130
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]	127		129
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]	8		11
Pension Plan | Domestic and international equity securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	8		11
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]	5		1
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]	5		1
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		3	[2]	5		$ 3
Postretirement Benefits Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	0		1
Postretirement Benefits Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	2		3
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		2
Postretirement Benefits Plan | Commingled Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	0		1
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]	2		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]	2		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
Postretirement Benefits Plan | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0		1
Postretirement Benefits Plan | Insurance contracts | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0		0
Postretirement Benefits Plan | Insurance contracts | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0		1
Postretirement Benefits Plan | Insurance contracts | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0		0
Postretirement Benefits Plan | Insurance contracts | Fair Value Measured at Net Asset Value Per Share
Defined Benefit Plan Disclosure [Line Items]
Plan assets at net asset value		$ 0		$ 0
[1] See Note 8 for further information regarding fair value measurement inputs and methods. See Note 8 for further information on fair value measurement inputs and methods.

Benefit Plans and Other Postr_6

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details)		1 Months Ended		12 Months Ended
		Jan. 31, 2024 USD ($)		Dec. 31, 2023 USD ($) plan		Dec. 31, 2022 USD ($)		Dec. 31, 2021 USD ($)
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1				$ 2,000,000
Obligation at Dec. 31						$ 2,000,000
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				$ (168,000,000)		(155,000,000)
Pension Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 660,000,000		657,000,000		877,000,000
Service cost				21,000,000		27,000,000		$ 30,000,000
Interest cost				36,000,000		25,000,000		25,000,000
Plan amendments				(1,000,000)		1,000,000
Actuarial (gain) loss				30,000,000		(139,000,000)
Benefit payments				(83,000,000)		(134,000,000)
Obligation at Dec. 31				660,000,000		657,000,000		877,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		562,000,000	[1]	570,000,000	[1]	853,000,000
Actual return (loss) on plan assets				52,000,000		(154,000,000)
Employer contributions				23,000,000		5,000,000
Benefit payments				(83,000,000)		(134,000,000)
Fair value of plan assets at Dec. 31				562,000,000	[1]	570,000,000	[1]	853,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status				(98,000,000)		(87,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss				321,000,000		309,000,000
Prior service (credit) cost				0		0
Total				321,000,000		309,000,000
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				11,000,000		12,000,000
Noncurrent regulatory assets				310,000,000		297,000,000
Total				$ 321,000,000		$ 309,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)				5.49%		5.80%
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]			$ 0		$ (38,000,000)		$ (35,000,000)
Defined Benefit Plan, Accumulated Benefit Obligation				599,000,000		600,000,000
Liability, Defined Benefit Plan, Current				0		0
Liability, Defined Benefit Plan, Noncurrent				(98,000,000)		(87,000,000)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position				$ (98,000,000)		$ (87,000,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				4.25%		3.75%		3.75%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Deferred Income Taxes						$ 0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income						0
Defined Benefit Plan, Accumulated Benefit Obligation				$ (599,000,000)		$ (600,000,000)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets				7.25%		6.60%		6.60%
Service cost				$ 21,000,000		$ 27,000,000		$ 30,000,000
Interest cost				36,000,000		25,000,000		25,000,000
Expected return on plan assets				(46,000,000)		(48,000,000)		(52,000,000)
Amortization of prior service cost (credit)				0		0		0
Amortization of net loss				11,000,000		24,000,000		34,000,000
Net periodic pension cost				22,000,000		66,000,000		72,000,000
Effects of regulation				16,000,000		(32,000,000)		(44,000,000)
Net benefit cost recognized for financial reporting				38,000,000		34,000,000		28,000,000
Pension Plan | NSP Minnesota [Member]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	[3]			5,000,000
Fair value of plan assets at Dec. 31	[3]					5,000,000
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period				23,000,000		5,000,000		34,000,000
Postretirement Benefits Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		42,000,000		48,000,000		64,000,000
Service cost				0		0		0
Interest cost				3,000,000		2,000,000		2,000,000
Plan amendments				0		0
Actuarial (gain) loss				(2,000,000)		(13,000,000)
Benefit payments				(7,000,000)		(5,000,000)
Obligation at Dec. 31				42,000,000		48,000,000		64,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		3,000,000	[3]	5,000,000		3,000,000
Actual return (loss) on plan assets				0		0
Employer contributions				5,000,000		7,000,000
Benefit payments				(7,000,000)		(5,000,000)
Fair value of plan assets at Dec. 31				3,000,000	[3]	5,000,000		3,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status				(39,000,000)		(43,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss				15,000,000		16,000,000
Prior service (credit) cost				0		(1,000,000)
Total				15,000,000		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
Noncurrent regulatory assets				14,000,000		14,000,000
Total				$ 15,000,000		$ 15,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)				5.54%		5.80%
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				(2,000,000)		(1,000,000)
Liability, Defined Benefit Plan, Noncurrent				(37,000,000)		(42,000,000)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position				$ (39,000,000)		$ (43,000,000)
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65				0.0700
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65				5.50%		5.50%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate				4.50%		4.50%
Period until ultimate trend rate is reached (in years)				$ 6		$ 7
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				0%		0%		0%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Deferred Income Taxes						$ 0
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%		4.10%		4.10%
Service cost				$ 0		$ 0		$ 0
Interest cost				3,000,000		2,000,000		2,000,000
Expected return on plan assets				0		0		0
Amortization of prior service cost (credit)				(1,000,000)		(3,000,000)		(3,000,000)
Amortization of net loss				0		1,000,000		2,000,000
Net periodic pension cost				2,000,000		0		1,000,000
Effects of regulation				0		0		0
Net benefit cost recognized for financial reporting				$ 2,000,000		$ 0		$ 1,000,000
Subsequent Event | Pension Plan | NSP Minnesota [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 41,000,000
[1] See Note 8 for further information regarding fair value measurement inputs and methods. 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 2022 and 2021, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $38 million and $35 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. See Note 8 for further information on fair value measurement inputs and methods.

Benefit Plans and Other Postr_7

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Postretirement Health Care Benefits [Abstract]
Total benefit obligation		$ 2
Estimated costs of health plan subsidies - VRP	$ 8
Estimated cost of other medical benefits - VRP		1
Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	42	48	$ 64
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 2	$ 0	1
Target pension asset allocations (as a percent)	100%	100%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate, VRP	0.0550
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	$ 2
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | Parent Company [Member]
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	12	$ 11
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	2	17
Pension Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	660	657	877
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 38	$ 34	$ 28
Target pension asset allocations (as a percent)	100%	100%
Domestic and international equity securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9%	16%
Domestic and international equity securities | Pension Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	31%	33%
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%	0%
Long-duration fixed income and interest rate swap securities | Pension Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	38%	38%
Short-to-intermediate fixed income securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	77%	71%
Short-to-intermediate fixed income securities | Pension Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9%	9%
Alternative investments | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13%	12%
Alternative investments | Pension Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	20%	18%
Cash | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	1%	1%
Cash | Pension Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	2%	2%

Benefit Plans and Other Postr_8

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefits Plan - USD ($) $ in Millions		Dec. 31, 2023		Dec. 31, 2022	Dec. 31, 2021
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 3	[1]	$ 5	$ 3
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		1
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	2		3
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]	2		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]	2		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		2
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		1
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
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		1
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		1
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 0		$ 0
[1] See Note 8 for further information on fair value measurement inputs and methods.

Benefit Plans and Other Postr_9

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($)		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 2,000,000
Obligation at Dec. 31				$ 2,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		(168,000,000)		(155,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Plan Amendments		0
Pension Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		657,000,000		877,000,000
Service cost		21,000,000		27,000,000		$ 30,000,000
Interest cost		36,000,000		25,000,000		25,000,000
Actuarial (gain) loss		30,000,000		(139,000,000)
Benefit payments		(83,000,000)		(134,000,000)
Obligation at Dec. 31		660,000,000		657,000,000		877,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		570,000,000	[1]	853,000,000
Actual return (loss) on plan assets		52,000,000		(154,000,000)
Employer contributions		23,000,000		5,000,000
Benefit payments		(83,000,000)		(134,000,000)
Fair value of plan assets at Dec. 31		562,000,000	[1]	570,000,000	[1]	853,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(98,000,000)		(87,000,000)
Current liabilities		0		0
Noncurrent liabilities		(98,000,000)		(87,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(98,000,000)		(87,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		321,000,000		309,000,000
Prior service (credit) cost		0		0
Total		321,000,000		309,000,000
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		310,000,000		297,000,000
Deferred income taxes				0
Net-of-tax accumulated other comprehensive income				0
Total		$ 321,000,000		$ 309,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.49%		5.80%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 21,000,000		$ 27,000,000		30,000,000
Interest cost		36,000,000		25,000,000		25,000,000
Expected return on plan assets		(46,000,000)		(48,000,000)		(52,000,000)
Amortization of prior service cost (credit)		0		0		0
Amortization of net loss		11,000,000		24,000,000		34,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]	0		38,000,000		35,000,000
Net periodic postretirement benefit cost		22,000,000		66,000,000		72,000,000
Significant Assumptions Used to Measure Costs [Abstract]
Plan amendments		(1,000,000)		1,000,000
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		11,000,000		12,000,000
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		16,000,000		(32,000,000)		(44,000,000)
Net benefit cost recognized for financial reporting		$ 38,000,000		$ 34,000,000		$ 28,000,000
Discount rate (as a percent)		5.80%		3.08%		2.71%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		4.25%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)		7.25%		6.60%		6.60%
Postretirement Benefits Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 48,000,000		$ 64,000,000
Service cost		0		0		$ 0
Interest cost		3,000,000		2,000,000		2,000,000
Actuarial (gain) loss		(2,000,000)		(13,000,000)
Benefit payments		(7,000,000)		(5,000,000)
Obligation at Dec. 31		42,000,000		48,000,000		64,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		5,000,000		3,000,000
Actual return (loss) on plan assets		0		0
Employer contributions		5,000,000		7,000,000
Benefit payments		(7,000,000)		(5,000,000)
Fair value of plan assets at Dec. 31		3,000,000	[3]	5,000,000		3,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(39,000,000)		(43,000,000)
Current liabilities		(2,000,000)		(1,000,000)
Noncurrent liabilities		(37,000,000)		(42,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(39,000,000)		(43,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		15,000,000		16,000,000
Prior service (credit) cost		0		(1,000,000)
Total		15,000,000		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		14,000,000		14,000,000
Deferred income taxes				0
Net-of-tax accumulated other comprehensive income		1,000,000		1,000,000
Total		$ 15,000,000		$ 15,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.54%		5.80%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%		6.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.50%		5.50%
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 6		$ 7
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0		0		0
Interest cost		3,000,000		2,000,000		2,000,000
Expected return on plan assets		0		0		0
Amortization of prior service cost (credit)		(1,000,000)		(3,000,000)		(3,000,000)
Amortization of net loss		0		1,000,000		2,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]	0		0		0
Net periodic postretirement benefit cost		2,000,000		0		1,000,000
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
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		0		0		0
Net benefit cost recognized for financial reporting		$ 2,000,000		$ 0		$ 1,000,000
Discount rate (as a percent)		5.80%		3.09%		2.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		0%		0%		0%
Expected average long-term rate of return on assets (as a percent)		5%		4.10%		4.10%
[1] See Note 8 for further information regarding fair value measurement inputs and methods. 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 2022 and 2021, as a result of lump-sum distributions during each plan year, NSP-Minnesota recorded a total pension settlement charge of $38 million and $35 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. See Note 8 for further information on fair value measurement inputs and methods.

Benefit Plans and Other Post_10

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Defined Contribution Plan, Administrative Expense			$ 14	$ 13	$ 12
Pension Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022			100
2023			56
2024			56
2025			56
2026			55
2027-2031			273
Pension Plan | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			50	50	131
Pension Plan | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 100
Pension Plan | NSP Minnesota [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			23	5	34
Pension Plan | NSP Minnesota [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 41
Postretirement Benefits Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022			5
2023			5
2024			4
2025			4
2026			4
2027-2031			15
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			11	13	15
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 11
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			$ 5	$ 7	$ 8
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 5

Commitments and Contingencies S

Commitments and Contingencies Sherco (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2021	Dec. 31, 2023	Jan. 27, 2021
Commitments and Contingencies Disclosure [Abstract]
Customer refund of previously recovered purchased power costs	$ 17
Amount MPUC previously disallowed related to Sherco outage			$ 22
DOC recommended refund		$ 56
XLI recommended refund		$ 72

Commitments and Contingencies M

Commitments and Contingencies MISO ROE Complaints (Details) - Federal Energy Regulatory Commission (FERC) [Member] - FERC Proceeding, MISO ROE Complaint [Member] - NSP Minnesota and NSP Wisconsin [Member] [Member]	1 Months Ended
	Feb. 28, 2015	Nov. 30, 2013
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates	12.38%	12.38%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties	8.67%	9.15%

Commitments and Contingencies_2

Commitments and Contingencies MGP Sites (Details) - Other MGP, Landfill, or Disposal Sites	Dec. 31, 2023 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

Commitments and Contingencies E

Commitments and Contingencies Environmental Requirements - Water and Waste (Details) $ in Millions	Dec. 31, 2023 USD ($)
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

Commitment and Contingencies AR

Commitment and Contingencies AROs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 2,727		$ 2,585
Amounts Incurred	(10)	[1]	(25)	[2]
Amounts Settled	(1)
Accretion	126		123
Cash flow revisions	(204)	[3]	(6)	[4]
Ending balance	2,658		2,727
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member]
Other Commitments [Line Items]
Legally restricted assets, for purposes of funding future nuclear decommissioning	3,211	[5]	2,882	[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	3,200		2,900
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	2,160		2,056
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0
Accretion	105		104
Cash flow revisions	(158)	[3]	0	[4]
Ending balance	2,107		2,160
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	416		384
Amounts Incurred	(10)	[1]	(25)	[2]
Amounts Settled	0
Accretion	15		15
Cash flow revisions	(17)	[3]	(8)	[4]
Ending balance	424		416
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	75		73
Amounts Incurred	0	[1]	0	[2]
Accretion	3		2
Cash flow revisions	0	[3]	0	[4]
Ending balance	77		75
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	16		16
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0
Accretion	1		0
Cash flow revisions	0	[3]	0	[4]
Ending balance	17		16
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	59		55
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0
Accretion	2		2
Cash flow revisions	(29)	[3]	2	[4]
Ending balance	32		59
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
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	$ (1)
[1] Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. Amounts incurred relate to the wind farms placed in service in 2022 (Dakota Range and Rock Aetna). 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. In 2022, AROs were revised for changes in timing and estimates of cash flows. Changes in electric wind AROs were related to the repowering and extended retirement date of Nobles. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments.

Indeterminate AROs (Details)

Indeterminate AROs (Details) $ in Millions	Dec. 31, 2023 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Indeterminate Costs Incurred, Asset Retirement Obligation Due to Asbestos	$ 0

Commitments and Contingencies,

Commitments and Contingencies, Nuclear Insurance (Details) - Nuclear Insurance $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Reactor Plant
Nuclear Insurance [Abstract]
Nuclear insurance coverage secured for the Company's public liability exposure	$ 450
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
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 15
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	32
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	16,200
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,800
Business Interruption Insurance Coverage Provided by NEIL	490
Business Interruption Insurance Coverage Provided by NEIL - Prairie Island	$ 420

Commitments and Contingencies N

Commitments and Contingencies Nuclear Fuel Disposal (Details) $ in Millions	Dec. 31, 2023 USD ($) Canister		Dec. 31, 2022 USD ($)
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring
Loss Contingencies [Line Items]
Decommissioning Fund Investments | $	$ 3,211	[1]	$ 2,882	[2]
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Nuclear Decommissioning Fund [Member]
Loss Contingencies [Line Items]
Decommissioning Fund Investments | $	$ 3,200		2,900
NSP Minnesota [Member]
Loss Contingencies [Line Items]
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds	100%
NSP Minnesota [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring
Loss Contingencies [Line Items]
Decommissioning Fund Investments | $	$ 3,200		$ 2,900
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	50
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 $51 million of other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments.

Commitments and Contingencies R

Commitments and Contingencies Regulatory Plant Decommissioning Recovery (Details) - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Asset Retirement Obligation	$ 2,658		$ 2,727		$ 2,585
NSP Minnesota [Member]
Public Utilities, General Disclosures [Line Items]
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds	100%
Nuclear Plant [Member]
Public Utilities, General Disclosures [Line Items]
Asset Retirement Obligation	$ 2,107		2,160		$ 2,056
Fair Value Measured on a Recurring Basis | Estimate of Fair Value Measurement [Member]
Public Utilities, General Disclosures [Line Items]
Decommissioning Fund Investments	3,211	[1]	2,882	[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	3,200		2,900
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	$ 3,200		$ 2,900
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $51 million of other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $48 million of rabbi trust assets and other miscellaneous investments.

Commitments and Contingencies_3

Commitments and Contingencies, Leases (Details) - USD ($)		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Short-term Lease, Cost		$ 2,000,000	$ 3,000,000	$ 2,000,000
Operating Lease, Weighted Average Discount Rate, Percent		4.60%
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		$ 834,000,000	634,000,000
Operating Lease, Right-of-Use Asset, Accumulated Depreciation		(395,000,000)	(310,000,000)
Operating lease right-of-use assets		439,000,000	324,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[1]	113,000,000	107,000,000	104,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2024		110,000,000
2025		112,000,000
2026		100,000,000
2027		83,000,000
2028		50,000,000
Thereafter		125,000,000
Total minimum obligation		580,000,000
Interest component of obligation		(117,000,000)
Operating Lease, Liability		463,000,000
Less current portion		(91,000,000)	(98,000,000)
Operating lease liabilities		372,000,000	256,000,000
Weighted Average Remaining lease term, operating		9.8
Property, Plant and Equipment, Other Types [Member]
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		125,000,000	78,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[2]	13,000,000	9,000,000	8,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2024		11,000,000
2025		11,000,000
2026		11,000,000
2027		11,000,000
2028		10,000,000
Thereafter		125,000,000
Total minimum obligation		179,000,000
Interest component of obligation		(80,000,000)
Operating Lease, Liability		99,000,000
Purchased Power Agreements
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		709,000,000	556,000,000
Lease, Cost [Abstract]
Operating Lease, Cost		100,000,000	$ 98,000,000	$ 96,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2024	[3],[4]	99,000,000
2025	[3],[4]	101,000,000
2026	[3],[4]	89,000,000
2027	[3],[4]	72,000,000
2028	[3],[4]	40,000,000
Thereafter	[3],[4]	0
Total minimum obligation	[3],[4]	401,000,000
Interest component of obligation	[3],[4]	(37,000,000)
Operating Lease, Liability	[3],[4]	$ 364,000,000
[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. Includes short-term lease expense o f $2 million, $3 million and $2 million for 2023, 2022 and 2021, respectively. Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. PPA operating leases contractually expire at various dates through 2039.

Commitments and Contingencies_4

Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Energy
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		$ 185	$ 182	$ 149
Estimated Future Payments Under PPAs [Abstract]
2024	[1]	174
2025	[1]	53
2026	[1]	10
2027	[1]	10
2028	[1]	10
Thereafter	[1]	18
Total	[1],[2]	275
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		62	$ 60	$ 55
Estimated Future Payments Under PPAs [Abstract]
2024		63
2025		27
2026		9
2027		8
2028		1
Thereafter		2
Total	[2]	$ 110
[1] Excludes contingent energy payments for renewable energy PPAs. Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Commitments and Contingencies_5

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	Dec. 31, 2023 USD ($)
Coal
Fuel Contracts [Abstract]
2024	$ 115
2025	62
2026	21
2027	1
2028	0
Thereafter	0
Total	199	[1]
Nuclear Fuel
Fuel Contracts [Abstract]
2024	142
2025	179
2026	63
2027	180
2028	50
Thereafter	177
Total	791	[1]
Natural Gas Supply
Fuel Contracts [Abstract]
2024	88
2025	1
2026	0
2027	0
2028	0
Thereafter	0
Total	89	[1]
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2024	148
2025	131
2026	128
2027	96
2028	28
Thereafter	47
Total	$ 578	[1]
[1] Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Commitments and Contingencies_6

Commitments and Contingencies, Variable Interest Entities (Details) - MW	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,347	1,322

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	$ 7,836
Accumulated other comprehensive (loss) income at end of period	8,207	$ 7,836
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	(16)	(17)
Net current period other comprehensive income	(2)	1
Accumulated other comprehensive (loss) income at end of period	(18)	(16)
Other comprehensive income (loss) before reclassifications	(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)	[1]
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	(2)	(3)
Net current period other comprehensive income	0	1
Accumulated other comprehensive (loss) income at end of period	(2)	(2)
Other comprehensive income (loss) before reclassifications	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	0
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	(18)	(20)
Net current period other comprehensive income	(2)	2
Accumulated other comprehensive (loss) income at end of period	(20)	(18)
Other comprehensive income (loss) before reclassifications	(3)
Total | Interest Rate Swap [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of interest rate hedges	$ (1)	$ (1)
[1] Included in interest charges.

Segments and Related Informat_3

Segments and Related Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Natural gas		$ 754	$ 1,022	$ 623
Other		48	45	39
Total operating revenues		6,043	6,684	5,756
Depreciation and amortization		981	1,014	926
Total interest charges and financing costs		304	279	258
Income tax benefit		(109)	(112)	(48)
Net income (loss)		707	675	606
Related Party Transaction - Electric Domestic Regulated Revenue		493	514	501
Related Party Transaction - Gas Domestic Regulated Revenue		1	0	1
Regulated Electricity
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues		5,242	5,618	5,095
Depreciation and amortization		909	953	869
Total interest charges and financing costs		278	257	240
Income tax benefit		(127)	(127)	(53)
Net income (loss)		648	626	566
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues		756	1,024	624
Depreciation and amortization		71	60	56
Total interest charges and financing costs		26	22	18
Income tax benefit		10	14	6
Net income (loss)		38	45	29
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization		1	1	1
Income tax benefit		8	1	(1)
Net income (loss)		21	4	11
Total revenues
Segment Reporting Information [Line Items]
Total operating revenues	[1],[2]	6,046	6,687	5,758
Total revenues | Regulated Electricity
Segment Reporting Information [Line Items]
Operating revenue, Regulated Electric	[2]	5,241	5,617	5,094
Total revenues | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural gas	[1]	754	1,022	623
Total revenues | All Other
Segment Reporting Information [Line Items]
Other		48	45	39
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total operating revenues		(3)	(3)	(2)
Intersegment Eliminations | Regulated Electricity
Segment Reporting Information [Line Items]
Operating revenue, Regulated Electric		1	1	1
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural gas		$ 2	$ 2	$ 1
[1] Operating revenues include $1 million, $0 million and $1 million of affiliate gas revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information. Operating revenues include $493 million, $514 million and $501 million of affiliate electric revenue for the years ended Dec. 31, 2023, 2022 and 2021, respectively. See Note 13 for further information.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
NSP-Wisconsin
Operating expenses
Other Receivables	$ 9	$ 4
Accounts payable to affiliates	0	0
PSCo
Operating expenses
Other Receivables	5	0
Accounts payable to affiliates	0	2
SPS
Operating expenses
Other Receivables	0	0
Accounts payable to affiliates	4	3
Other subsidiaries of Xcel Energy Inc.
Operating expenses
Other Receivables	1	41
Accounts payable to affiliates	85	84
Xcel Energy [Member]
Operating expenses
Other Receivables	15	45
Accounts payable to affiliates	89	89
Purchased Power
Operating expenses
Costs and Expenses, Related Party	63	70	$ 67
Transmission Expense
Operating expenses
Costs and Expenses, Related Party	142	132	121
Other Expense
Operating expenses
Costs and Expenses, Related Party	719	673	615
Interest Expense
Operating expenses
Costs and Expenses, Related Party	5	1	0
Electricity, US Regulated | Xcel Energy [Member]
Operating expenses
Interest and Other Income	1	1	0
Revenues	493	514	501
Natural Gas, US Regulated | Xcel Energy [Member]
Operating expenses
Revenues	$ 1	$ 0	$ 1

Compensation Related Costs, P_2

Compensation Related Costs, Postemployment Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 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

Schedule II, Valuation and Qu_2

Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 46	$ 45	$ 33
Charged to costs and expenses		30	21	24
Charged to other accounts	[1]	6	6	5
Deductions from reserves	[2]	(34)	(26)	(17)
Balance at Dec. 31		$ 48	$ 46	$ 45
[1] Recovery of amounts previously written-off. Deductions related primarily to bad debt write-offs.